MUD FACTS Written By Raafat Hammad
HYDRODYNAMICS: Viscosity of Fluids : All fluids exhibit a certain resistance to flow, In general terms, a fluid is often described as being thick or thin. A thick fluid crude oil has a high viscosity than thin fluid such as water. In general viscosity is defined as the relationship between the shear stress (flow pressure) and the shear rate (flow rate), shear stress and shear rate cause deformation of mud matter and thus affect the flow property of the drilling fluid.
1. Shear stress: It can b defined as the force required to overcome the fluid resistance to flow divided by the area that force acting on. Shear stress (t) =force applied (dynes) / A (cm2) = dunes / cm2 Where: A is the surface area subjected to stress. 2. Shear rate: It can be defined as the relative viscosity of the fluid layers, or elements divided by their normal separation distance. Shear rate (y) = V (cm/sec) / H (cm) = sec -1 FIGURE Assume that two flat plates are placed parallel too each other, at 1 cm apart the top plat is free to move, while the bottom plat is fixed fixed , the space between between the two plates is filled filled with fluid . So if a force is then applied to the top plate, so that it moves with a constant velocity of 1 cm /sec, that force will be transmitted to the fluid, thus causing the layers within to move also but with different rates. The layers that is close to the moving plate will move approximately with the same velocity of the plat, while the movement of the force that is transmitted through the layers diminishes until the movement at the fixed plat is nearly equal zero. Thus viscosity can be defined as a measure of the resistance of a fluid to flow. Viscosity = shear stress / shear rate. Drill Fluid Rheology :
heology can be defined as the science of the deformation d eformation of the flow of matter. R heology It as usually described by viscosity and gel strength. Types of flow regimes: • Laminar flow. • Turbulent flow. N.B. The type of flow is usually depending on the flow rate (SPM * POP), the flow pressure and the relative of the flow channel. • Laminar flow: Is generally associated with low flow rate, low fluid velocities and with fluid movement in uniform layers. In laminar flow the force (pressure) required to induce flow increases as the fluid velocity increase.
CURVE In laminar flow, the fluid particles tend to move in straight lines parallel to direction of flow. The layers near the wall of the flow channel tend to move at a lower velocity than that exists in the center of the flow channel, thus
the flow profile of the fluid in case of laminar flow when move a cylindrical pipe will be in a sort of concentric cylinder. FIGURE •
Turbulent flow:
In generally occurs at high flow rates, high fluid velocities, and is characterized by an erratic, random movement of the drilling fluid particles. A flowing fluid is generally considered to be an either laminar or turbulent flow. There is a very critical critical period period called called transitio transitional nal period between between two regimes when the movement movement of fluid fluid particles is no longer complete laminar, nor has it yet become complete random . I.e.: If the flow pressure is reduced slightly, the fluid particles will return to the laminar movement. Conversely, if the flow pressure is increased sufficiently the fluid particles will assume the random flow patterns associated with the turbulent flow. This transition transition occurs at some critical critical velocity, velocity, which is generally generally governed by the ratio of the fluids internal forces to its viscous forces this ratio is called Reynolds number (Nre) Nre = [diameter of the flow channel *average flow velocity * fluid density]/ fluid viscosity CURVE N.B. Shear stress and shear rate data, allows accurate determinations of the fluid behavior under varying flow conditions. This data then provides the basis for further calculations used to determine several important aspects related to the drilling fluids parameters. I.e.: proper understanding and application of rheological principles can be valuable aid in determination of dynamic performance of drilling fluid in order to establish and maintain the most effective properties for efficient and economical drilling fluid performance. These further calculations are : 1. Fl Flui uid d ve velo loci city ty.. 2. Cal Calcul culati ation on of the the system system press pressure ure loss losses. es. 3. Cal Calcul culati ation on of surg surgee and swab swab press pressure ures. s. 4. Bit and jet noz nozzle zle hyd hydrau raulic lics. s. 5. Rel Relati ative ve hole hole cleani cleaning ng effi efficie ciency ncy.. 6. Equ Equiva ivalen lentt circu circulat lating ing den densit sity. y. 7. Estim Estimation ation of the the relativ relativee extent extent of hole erosi erosion. on. Reynolds Number:
a. In pipe Nr = 15.46 dvw / PV. b. In annulus Nr = 15.46(dh-dp) vw / PV. Fluid velocity (ft/min): 2 a. In pipe V = 24.51 GPM / d . 2 2 b. In annulus V = 24.51 GPM / (dh – dp ) OR = POP (bbl/min)/ Ann. Vol. (bbl/ft). Critical Velocity (ft/min): a.
In pipe V = 64.57 PV + 64.57
b.
In annulus V = 64.57 PV+ 64.57
[(PV)2+ 12.3 d2YP W] / wd. [(PV)2+9.26(dh – dp)2YP W] /w(dh – dp).
Slip Velocity Vs (ft/min): 2 a. Laminar Flow = 3210 (Wc – W) D V / 339 YP (dh – dp) + PV V.
b.
Turbulent Flow = 60
[D(Wc – W) /W] .
I.e.: Slip Velocity is that velocity of desendigration of cuttings, according to its specific gravity, cutting size and hole size, which acts against fluid velocity, ca rrying capacity and viscosity of mud. WHERE : V = fluid velocity (ft/min). GPM = gallons per min. d = hole diameter.(in) D = cutting diameter(in). Wc = cutting density (PPG). L = section length (ft). W = mud weight (PPG). Vc = critical velocity(ft/min). PV = plastic viscosity (cp). YP = yield point.(lbs./100sq ft). TVD = true vertical depth(ft). Pressure drop = [Mwt in – Mwt out] * 0.0519 * TVD.
Dp = pipe diameter (in)
MUD FACTS FACTS AND PRINCIPLES PRINCIPLES
PLASTIC VISCOSITY (PV) ========================== ======================================= ============= The friction to resist moving of mud layers against each other in dynamic state In other words Is the resistance of the fluid particles to move against each other in dynamic state, which is caused primary by the friction between the suspended particles and the viscosity of the continuous liquid phase. NB: PV is is a function of solids I.e.: plastic viscosity depends on the concentration of solids, also size and shape of solids. PV is affected by the following: following :
1- Size Size and and dist distrib ributi ution on of of soli solids ds 2- Shape Shape and and conc concent entrat ration ion of soli solids. ds. 3- Flui Fluids ds phas phasee vis visco cosi sity ty
CAUTION !S T O
P
IN GENERAL: PV gives an NB: * The finer the solids, the higher the PV due to the increase of surface area which surrounded by more Volume of water. *PV may be called (bit viscosity) which is equivalent to the viscosity of mud coming out of the bit, because PV has to be measured at high shear rate. *PV = 600 reading – 300 reading CAUSES OF PLASTIC VISCOSITY (PV) INCREASE: INCREASE:
1- Increases of solids concentration a- dril rilled led sol solid idss b- commercial solids solids 1- Barite 2- Bentonite 2-Increases of solids surface area. Non dispersed solids
• • •
less surface area less quantity of adsorbed water more available free water
Dispersed solids
* more surface area * more quantity of adsorbed water *low available free water
• • • • * • •
low PV low YP low GEL low viscosity High capability to removed thin fluids thin rigid cake
*high PV *high YP *high GEL *high viscosity *low capability to be removed * thick fluids *thick cake
NB: Increase of PV direct related with increases of YP, also with increases of annular pressure losses and with increases increases of ECD value, and and decreases of ROP value. value. METHODS OF DECREASING PV: ================================= 1- DILUTION: a- with with wate waterr in case case of wate waterr base base mud. mud. b- With diesel in case of oil base base mud. c- With With clea clean n pre premi mixe xed d mud mud.. 2-REMOVAL OF SOLIDS BY: a b-
soli solids ds con contr trol ol equ equip ipme ment nt’s ’s settling Natural settling: settling: is effective effective because some of solids are colloidal colloidal and suspended. suspended. (NB: settling does not take place by stopping agitation.) c- addi adding ng Flo Flocc ccul ulan ants ts:: This is done by flocculate solids and decrease surface area of solids. Flocculants are chemicals added to collect the solids together to decrease surface area of solids and thus can easily remove solids out of mud.
NB: treating by dilution dilution is more effective effective than chemical treatment.
YIELD POINT (YP ) : IT’S THE ELECTRO – CHEMICALS ATTRACTION BETWEEN SOLIDS OR MUD COMPONENTS IN OTHER WORDS: IT’S THE FORCE REQUIRED TO SLIDE ONE LAYER OF THE MUD OVER ANOTHER These forces are a result of the +ve and –ve charges located on the surface of fluids layers. YP is the measurement of these forces and its effect on fluids under flowing condition of drilling fluid.
NB: YP is the measure measure of Flocculation In general YP gives some indication of hole cleaning ability of the fluid, when the fluid is in motion CAUSES OF (YP) INCREASE: (CAUSES OF FLOCCULATION) ========================== ========== ============================= =========================== ====================== ======== 1- FLOC FLOCCUL CULATI ATION ON DUE DUE TO TEMPE TEMPERAT RATUR URE E: ==================================== THIS TAKE PLACE BY A- CHEMI CHEMICAL CAL DEGRA DEGRADA DATI TION ON B- CLAY CLAY MOV MOVEM EMEN ENT T C- DEHY DEHYDR DRAT ATIION
**Over 150 F the space between clay particles increases causes over hydration on the clay particles, so Water is no longer available in the system to keep mud flows, that’s why mud become more thicker
**Over 350F a chemical degradation to clay particles occurs, causes an increase in activating ions and by term an increase in Electro-chemicals Electro-chemicals attraction occurs, so Flocculation occurs accompanied by increase in YP.
TO DECREASE (YP ) DUE TO TEMPERATURE: TEMPERATURE : (TEMP FLOCCULATION ) A- Dilute Dilute with with wate waterr or fresh fresh mud mud B- Reduce Reduce clay clay as as poss possibl iblee C- Add high high temp temp Defl Deflocc occula ulant nt
2- FLOCCULATION CAUSED BY SOLIDS CROWDING: REASONS: ABCD-
Weighting Weighting up up of mud ( water water should should be added added to wet wet barite) barite) Poor Poor solid solid cont control rol equipm equipment ent Reac Reacti tive ve form format atio ions ns Dehy Dehydr drat atio ion. n.
TO DECREASE (YP) CAUSED BY SOLID CROWDING: A- Dilute Dilute with with wate waterr or fresh fresh mud. mud. B- Use high high effici efficiency ency solid solid control control equipme equipment nt
3- FLOCCULATION CAUSED BY ALKALINITY CHANGES: REASONS:
ABCDE-
PH increas increases es or decrease decreasess due to cement cement contam contaminati ination. on. Lime ime add addit itio ion. n. Acid Acid gas gas influx influx (CO2 (CO2 , H2S H2S ) Carbo arbona nate te Incorr Incorrect ect Pm/ Pm/Pf Pf ratio ratio (li (lime me mud mud )
NB: High PH causes flocculation flocculation due to increases increases of attraction attraction forces between between particles.
TO DECREASE (YP) CAUSED BY ALKALINITY CHANGES: A- Increases Increases of PH by adding adding caustic caustic soda or or caustic caustic potash. potash. B- Decreases of PH by dilution or adding organic acid acid such as Lignite Lignite (3.8 PH) or or lignosulfonate lignosulfonate (4.2 PH). C- Adjusting Adjusting Pm/Pf Pm/Pf ratio ratio by adding adding lime lime or causti causticc soda.
4- FLOCCULATION CAUSED BY COMMERCIAL ADDITIVES ( BENTONITE & POLYMERS): A- Overdoses of polymers polymers (such as viscosifiers, viscosifiers, flocculants, flocculants, water water loss reducer ) B- Exce Excess ss of of bent benton onit ite. e.
TO DECREASE (YP) CAUSED BY COMMERCIAL ADDITIVES: A- Dilu Dilute te wit with h wat water er B- Adding Adding defloc defloccul culant ants. s.
5- FLOCCU FLOCCULATIO LATION N CAUSED CAUSED BY CHEMICA CHEMICAL L CONTAM CONTAMINATION INATION:: ABCDEF-
Salt Salt/s /sal altt wat water er Calcium Carbo arbona nate tess Cement H2S/CO2 Anhy Anhydr drit ite/ e/Gy Gypsu psum. m.
TO DECREASE (YP) CAUSED BY CHEMICAL CONTAMINATION: A- Add Add def deflo locc ccul ulan antt B- Chemic Chemicall ally y remove remove the contam contamina inate te C- Dilute
RELATION BETWEEN (PV) AND (YP): 1- If both both (PV) and and (YP) incre increases: ases: ( soli solid d content content problem) problem) TREATMENT: A- Dilu Diluti tion on B- Maintain Maintain solid solid control control equipme equipment. nt.
NB: Don’t add thinner otherwise (YP) will dramatically decreased and (PV) still high and this will causes barite settling. 2- If (PV) is steady steady and (YP) (YP) increases increases : ( chemical chemical contaminati contamination on problem-YP problem-YP problem) problem) TREATMENT: A- Dilu Diluti tion on B- Add Defloc Defloccul culant antss NB: In low saline mud and as a result of presence of CL ions (at a certain limit) the (YP) increases with no effect on (PV) value, this take place due to increases of Electro-chemical attraction between ions in mud, so if same salinity required, add deflocculants, And if we need to reduce salinity we had h ad to dilute with water. 3- If (PV) (PV) and (YP) (YP) decreased decreased : (in (in case of high saline saline mud) mud) TREATMENT: A- Add Add Floc Floccu cula lant ntss B- Add Add Visc Viscos osif ifie iers rs C- Add Add Wate Waterr redu reduce cers rs.. NB: In high saline mud, the % of free CL ions will increase in the mud and thus will retrieve water from bentonite plates back to the system, so both PV and YP will decreases. That besides increasing of frees H2O and thus increases of water loss.
GENERAL NOTES: 1- PV = 600 REA READIN DING G - 300 REA READIN DING G 2- YP = 30 300 0 RE READ ADIN ING G - PV 3- YP IS A MEASUREME MEASUREMENT NT OF THE THE CHARGES CHARGES ON ON THE SOLID SOLID.. 4- ALW ALWAYS AYS KEEP KEEP PV PV LOWEST LOWEST AS AS POSSIB POSSIBLE. LE. 5- PV IS A FUNCT FUNCTION ION OF SOL SOLIDS IDS.. 6-
IF PV INCREASES, YP MUST BE INCREASE DUE TO CROWDING EFFECT OF FINE SOLIDS. THES TH ESE E FI FINE NE SO SOLI LIDS DS PU PUSH SHES ES TH THE E CH CHAR ARGE GES S TO EA EACH CH OT OTHE HER, R, SO TH THE E EL ELEC ECTR TROOCHEM CH EMIC ICAL AL AT ATTR TRAC ACTI TION ON BE BETW TWEE EEN N MU MUD D CO COMP MPON ONEN ENTS TS IN INCR CREA EASES SES,, CA CAUS USIN ING G YP INCREASE.
7- CHEMICAL CHEMICAL CONTAMINA CONTAMINATION TION Ca, Mg Mg AND SALT, SALT, WILL INCREASE INCREASE YP WITH WITH NO EFFECT EFFECT ON PV. SO: IF PV INCREASED, YP MUST BE INCREASED TOO. BUT YP INCREASING DOES NOT AFFECT THE PV VALUE.
GEL STRENGTH: Is the measurement of chemical attraction forces between mud particles under static conditions. GEL Strength is an indicator for low shear rate rheology at 3 rpm reading ( V.G meter) Gel strength importance:
A- Low gel streng strength th : causes causes 1- settling settling of cutting cutting and barit baritee in static static’s ’s conditi conditions ons 2- building building up of cuttings cuttings beds in in deviated deviated wells wells B- High High gel stre strengt ngth h : causes causes 1- increasing increasing pressur pressuree in break circul circulation ation to break break down gel( gel( may break break down format formation ion and causes mud losses ) 2- Increasing Increasing applied applied pressu pressure re to the the formation formation while while running running in in hole. (Might break down formation, causes mud losses) 3- Swabb Swabbin ing g whil whilee pull pull out of hol hole. e. 4- Poor cement cement jobs( jobs( as gel gel are hard hard to break, break, so that causes causes channeli channeling ng of cement) cement)
TYPES OF GEL: 1- Fragile or flat Gel: Gel strength of 10 minute is slightly higher than 10 seconds gel even if 10 seconds gel reading is high. This gel can be easily broken by low pump pressure. This type of gel has low swab and surge pressure.
2- Progres Progressiv sivee or elevate elevated d Gel: Gel strength increases significantly after 10 minute, even if 10 seconds gel is low. Causes of Progressive Gel:
1234-
Reactive Reactive formation formation resultin resulting g in high percentag percentagee of reactive reactive solids. solids. Soli Solids ds cro crowd wdin ing. g. In suff suffici icient ent defl deflocc occula ulatio tion. n. Carbona Carbonate te contami contaminati nation on (CO3& (CO3& HCO3). HCO3).
NB: Relation between Gel,YP, and Viscosity, Cake and pore hole diameter:--The increases of viscosity causes increase in YP & Gel, where too much increase of viscosity causes removed of filter cake and may causes wash in bore hole diameter.
FILTRATION: Is the rate of water loss of mud into formations There are two aspects of the filtration phenomenon :
1- The quantity quantity of filtrate filtrate which is is the volume volume of filtrate filtrate that invades invades the formati formation. on. (Anyhow lowering the water loss helps in hole stability) 2- The quality quality of filtra filtrate, te, which gives gives an idea idea about about the type type and concentr concentrati ation on of materi materials als dissolv dissolved ed in filtrate. This gives an idea about the extend of stability of mud resulting from chemical interaction forces between mud components, also gives an idea about the amount of contaminants dissolved in mud (LGS, SALT and Chemical contaminants) that Contributes this stability. NB: 5ppb water loss reducer ==== water loss = +/- 3.0
FILTER CAKE: IS THE MEASUREMENT MEASUREMENT OF THE RELATIVE AMOUNT AMOUNT OF MUD SHEETS DEPOSITED DEPOSITED ON THE PORE HOLE FORMATION SURFACE Evaluation of filter cake depends mainly on two items: 1- QUALITY: A- Impe Imperm rmeab eable le B- Non Non Poro Porous us This much affected by: • percentage of solid in mud • shape and size of solids • chemical contaminant in mud 2- QUAL QUALIT ITY: Y: (TH (THIN IN OR OR THIC THICK) K) Cake must be thin to minimize well sticking and reduce friction forces between drill string and pore hole wall. This is much affected by: • Quantity of water loss. • Solid content in mud • Chemical contaminant RELATION BETWEEN WATER LOSS AND FILTER CAKE.
• • • • •
Isolating the formation from the drilling fluids will minimize the potentially detrimental interaction between Filtrate and exposed formation and thus control the hole stability, this is complied by controlling: Water loss Quality and quantity of filter cake. In other word minimize water loss by mean of water loss reducers together with getting rid of colloidal
•
Materials (LGS) off mud and chemical treatment of che mical contaminants .
SOLIDS: TYPES OF SOLIDS:
A- High gravity gravity solids solids (Ca CO3 +Barite) +Barite) B- Low gravity gravity solids solids (drille (drilled d solids solids + bentonite) bentonite) Increases of drilled solids effect: 1- incr increa ease se of of mud mud wei weight ght 2- incr increa ease se of of visc viscos osit ity y 3- increase of Gel = may leads to gellation NB: Gel must be obtained from bentonite or polymers not from drilled drilled solids (to keep cutting suspended in mud in static case not to be settled) 4- Incr Increas easee of wate waterr loss loss.. 5- Incr Increa ease se of PV & YP YP 6- Increa Increase se cake cake thickne thickness ss and poro porosit sity. y. NB: Increase of high gravity solids in mud leads to increases in mud weight only, when low gravity solids Increase in mud leads to all pervious effects and may causes flocculation in mud. 7-
Severe cut to PH =which may leads to bicarbonate problem. p roblem.
Removing solids off mud produces the following benefits: 1- Improve Improve filter cake cake quality (less (less coarse drilled drilled solids) solids) results results in a less permeabl permeablee and less porous cake. Improving cake quality (thinner and tougher) minimize wall sticking and pore hole wall And thus reducing pipes corrosion and minimizes pressure produced on formation resulting from those friction forces (surge ) and thus reducing fluid losses. 2- A decrease decrease in concentration concentration of drilled drilled solids contribut contributes es to improve improve and maintain rheological rheological and other other mud properties and thus reduce mud maintenance cost. Increase of solids in mud can be detected by: 1- We Weig ight htin ing g mud mud 2- Evaporating Evaporating and condensing condensing mud mud fluid in a cylinder, cylinder, leaving leaving solid residual residual behind. behind. 3- Incr Increa ease se of PV
BENEFITS OF OBTAINING LOW PERCENTAGE OF LOW GRAVITY SOLIDS (LGS ) IN MUD : 1- Bett Better er hol holee condi conditi tion on 2- Reduc Reducee tor torqu quee and and drag drag 3- Reduce Reduce swab swab and surge surge pres pressur suree 4- Reduce Reduce tendenc tendency y for differ different ential ial stuck stuck.. 5- Fewer possibilit possibility y of stuck of logging logging tool. 6- Impr Improv ovee bit bit run run 7- Reduce Reduce bit bit and stab stabili ilizer zer ball balling ing 8- Bett Better er hole hole sta stabi bili lity ty NB: As increase of o f LGS % in mud causes an increase in mud weight and thus increases the hydrostatic head of mud column and by turn ECD. In other words increase the imposed pressure on formation which may exceed fracture pressure of the formation leading to a loss of circulation.
9- Keep PV low and and thus obtaining obtaining higher higher penetra penetration tion rate. rate. 10- Low abrasive LGS in mud reduces equipment wear and repair 11- Low abrasive LGS in in mud minimize minimize pipe washout. 12- Better Better cement jobs. 13- Better condition drilling fluid, thus low rate of dilution dilution and mud treatment, which Reduces mud cost.
Effect of solid size on ROP: Particles less than 1.0 micron decrease rate of penetration 12 times more than that which is higher than 1.0 micron because: 1- PV incre ncreas asee 2- Surface area for adsorption of water increases NB: 6-8 % colloidal solids adsorb 50% of water 3- Since percentage percentage of adsorbed adsorbed water increas increases, es, the mud will become become thicker thicker which may lead lead to flocculation flocculation of mud. Solid analysis determines: • % LGS and HGS • Mass balance calculation methods • Salinity corrections • Percentage of reactive solids • Percentage of bentonite and drilled solids • Cation exchange capacity (CEC) of bentonite and shale.
Remove solids by: 1- dum dump and and dilu diluti tion on 2- mechanical mechanical remova removall (solid (solid control control equipme equipment) nt) 3- Set Settling. NB: Some times diesel acts like solids, making making what is known as (mechanical solids) causing increase in PV,YP and Viscosity, this take place as a diesel in retort make a sort of droplets which don’t condense and thus gives slightly increase in solid percentage.
NB: NEVER INCREASE MUD WEIGHT WITH DRILLED SOLIDS ( LGS).
I.e.: never to put off solid control equipment to increase mud weight Example: To increase mud weight 0.1 PPG with drilled solids, that means ==0.1 X 2.6 X 42 = 10.92 ppb of low gravity solids which is too high and will cause a lot of solid problems as mentioned before. be fore.
SOLID CONTROL EQUIPMENT Solid Control Depending on: 1. Sc Scrreening. 2. Ce Cent ntri rifu fuga gall force force.. 3. Co Comb mbina inati tion on of bot both. h.
A. Sc Scre reen en De Devi vice ce:: This depends on: • Screening area and number of mesh. • Pump out put. • Solids load or penetration rate. • Mud viscosity. Factors Affecting Shaker Efficiency and Solid Removal: 1. Scre Screen en sel selec ecti tion on:: Selecting the right screen for shakers recommended to remove the maximum amount of solids of mud, and limits solids returning to mud system. Screen selection depends on: • Amount and shape of solids to be removed. • Circulating rate. • Viscosity. • Screen life expectancy. NB: 1. You will normal normally ly remove remove some finer finer solids solids than the the mesh size size due to piggy – backing . 2. Changing Changing wire diamet diameter er will change the the cut point point although although mesh mesh is the the same. same. 3. Fine screen screen anticipating anticipating losing losing mesh mesh water due to increase increase of surface surface area on smaller smaller solids solids which which are removed. Screen Types: a. Sandwich: If it’s a 40 mesh I.E.: it is accurately 80 mesh. Advantages: never plugged with sand. Disadvantages : plugged with gumbo shales. b. Recta Rectangu ngular lar openi opening. ng. c. Plain wea weave. d. Conv Conven enti tion onal al.. Advantages: resist more than sandwich. Disadvantages: plugged with sand faster than sandwich. e. Oblong: The best square mesh screens. f. Pyramidal: Advantages: never plugged with sand. Disadvantages: plugged with gumbo shales. What does screen mesh means? Mesh means the linear measurements of number of openings per square inch. I.E: Mesh counts opening per square inch. 80 openings per square inch. • EG: 80 mesh • One mesh includes width of one opening plus width of one wire. • Mesh count only tells the number of openings per linear inch in each direction. • Changing wire diameter without changing mesh will change the cut point although mesh is the same.
• Size openings depend on mesh count and wire size. NB: If screens are cutted at the same point several times you have to change the support cushion(Page6-10). Type of Motion: A. Circ Circul ular ar.. B. Elli Ellipt ptic ical al.. C. Long Longit itud udin inal al.. Circular and elliptical damage faster than longitudinal. But elliptical is better than circular where the solids are ex posed to more surface area at the screen. Angle of Deck: • Horizontal decks Have a higher liquid handling capacity than the sloped deck shakers, since the liquid has no tendency to run off the end of the shakers. • Sloped decks shakers: Have a higher solid handling capacity because the deck angle tends to make solids fall off the unit as it vibrates. NB: Screen motion and deck angle controls: 1) Rate of travel travel of cuttin cuttings gs along along scre screen. en. 2) Soli Solid d cap capac acit ity y. Distribution of fluid carrying solids on screens. 3) Flui Fluid d capa capaci city ty.. Flow Capacity: a. As PV increases flow capacity decreases. b. As mesh screens increase flow capacity increase. c. % screen covered increase flow capacity increase. d. Plugging effect increase flow capacity increase. PS: Screens have a viscosity and solids limit. Precautions; • Wash down screens before trips. • Keep screens clean and you will reduce blinding and plugging effect. Amplitude or Stroke Length: • Shakers are available with stroke lengths from 0.025 to 0.5 inches. The greater the stroke length , the higher solid removal because of the greater g reater the unit the unit handling capacity. c apacity. • Long strokes that forces thick fluids through the screen openings, also tend to force solids into the screens openings which cause blinding or o r partially blinding that particularly while handling sticky solids. Speed of Rotation: The general vibration frequency for shakers is 1100 to 3300 RPM. Shale shaker (G) Force: The common expression for the amount force generated by a shaker is G force. PS: Cut point of shaker means that all cuttings above that size of mesh screens will be separated on the shaker, below that size will pass from mesh screens of shaker back to system until removed with other solid control equipments. Cut point Millimicrons.
In General the Optimum Shale Shaker Operation Depends on: • Mounting and Leveling: Shakers must be leveled according to GPM not too much to the front so as not to lose mud. Or not too much up so as cuttings do not accumulate on the back sides of screens which by turn will cause too much load on that part of screens and thus may cause screen cut and by turn solids will escape into system. • Provide required voltage and frequency . • Vibrator should rotate in proper direction. • Install proper screens and proper support cushions. Proper and screen size is recommended so as not to have too narrow mesh and thus solids may plug screens and thus lose mud at shakers OR too wide and thus allow cuttings to pass into system and thus increase solids percentage in mud. Also make sure that sealing rubber (support cushions) of screens is proper and not small or cutted otherwise the solids will escape into system through cutted points. • Tension screens properly. • Size of mesh screens so as mud to cover 75 – 80 % of length. • Use water hose to wash down screens on trips. • You need partial plugging of mesh screens to aid in flow capacity and cutting removal. • Make sure that the bypath of shakers is not leaking. Otherwise solids will escape to system. • The volume of fluid lost on shale shakers per unit time depends on 1. Shak Shaker er desi design gn.. 2. Scre Screen en mes mesh h and and type type.. 3. Drilli Drilling ng fluid fluid proper propertie ties. s. 4. Sol Solid load loadin ing. g. PS: If only 50 % or less of the screen area is covered with mud, finer mesh screens is recommend. Inspite that without changing screens, the operating o nes can become partially blocked with time by cuttings wedge in the open screens (blinded) or by sediments/ residue/ mud dried on the wire cloth(coated).
B. Cen Centri trifug fugal al Dev Device ice:: Depends on separating solids based on size and specific gravity of solids. The centrifugal separator mechanically subjects the fluid to increased G forces and thus increases the settling rate of particles by mean of this method both heavy – coarse and light – fine fractions are separated of mud. Desired fractions of solids are then selected and return to the system. This recharging works well with both low density(low gravity solids), and high gravity fluids. FIGURE Hydrocyclones Performance Depend on: • Fluid viscosity. • Mechanical condition of cones. • Head at cone manifold(Feed pressure = 30 – 40 psi. • Solid load. Hydrocyclones Instillation & Maintenance: • Flow capacity should exceed rig circulating rate by 10 – 20 %. mechanica l agitators. • Eliminate mud guns and use mechanical • Recommended individual centrifugal pump for each set of Hydrocyclones. • Pumps properly sized to give recommended head at Hydrocyclones (35 psi). • Lines properly sized and short as possible.
• Suction out of one compartment, and discharge down stream in next • Replace only worn cones or nozzles. • Do not bypath shakers, as bypassing shakers causes most plugged cones. • Run as fine shale shaker screens as possible. • Operate in spray discharge for higher efficiency. • Periodically unplug (clean). NB: If keeping the previous percussion you will get the best solid separation. Also separation depends on: 1. specific gravity of solids (separation). 2. Size Size of partic particles les (separ (separati ation) on).. 3. Centri Centrifug fugal al forc forcee (sep (separa aratio tion). n). 4. Liquid Liquid phase phase visco viscosit sity y (separ (separati ation) on).. 5. Solid Solid loa load d (sepa (separa rati tion on). ). 6. Feed pres pressur suree optim optimum um (separ (separati ation) on).. 7. Mechani Mechanical cal condi conditio tion n (separ (separati ation) on).. NB1: As centrifugal forces increases the cut point decreases (I.E. decrease the size of separated particles). NB2: As viscosity increases the cut point increases (I.E. increase the size of separated particles). PS: Under Flow GPM (equipment) = 1.25 X GPM (rig). How heavy should cone underflow be? • Depends on size and nature of solids in feed. • Cone should be in spray discharge. • Cone underflow should be heavier than feed. • Desander underflow should be heavier than desilter underflow.
Hydrocyclones Optimistic Cut Point Centrifugal force increase Size 12” (Desander) 6” (desilter+M.C) 4” (desilter+M.C) 3” (desilter+M.C) 2” (desilter+M.C)
D 50 microns 65 - 70 25 –32 16 –18 12 7 -10
Effect of PV 0n separation 4” cone Mud PV PV (c (cp.) 1 10 23
D 50 50 mic micrrons 16 18 29
The higher the viscosity and PV the lower the efficiency of the equipment. eq uipment.
Effects of solids 0n separation 4” cone YP = 1
PV = 7
Solids % 1.2 2.05 2.37 3.9
solids %
D 50 microns 18 22.5 19 27
Hydrocyclones Rope Versus Versus spray discharge
Rope spray
Discharge 4 GPM 3 GPM
Wt(PPG) 14.5 13
Solids 46% 35%
Lb./hour 2392 3640
lb lb./day 57403 87360
NB: 1. Cone Coness proces processes ses 125 125 – 150 % of of the flow flow line line GPM. GPM. 2. Optim Optimum um pressure pressure on the solid control control equipment equipment = M.wt X (distanc (distancee between pumps pumps of solid control control equipments 75ft and the equipment itself) X 0.0519. GPM of Solid Control Equipment: a. Measure how much time needed to fill a viscosity cup to the mark from one cone. Convert seconds to minutes. NB: viscosity cup = ¼ gallon. Say in 8 min. ∴ 0.25 gallon was filled in 8 min. ∴ 0.25/8 = 0.03125 GPM for one cone. b. Multiply by number of cones to get GPM of equipment. a. Multi Multiply ply by 60 minut minutes es to get get gall gallon on / hour. hour. b. Multiply by 42 minutes to get bbl / hour. NB: On calculating equipment losses always try to match the GPM of equipment with equipment losses. PS: Never measure M.wt with drilled solids. I.E: Never to put off solid control equipments to increase mud weight. EG: To increase M.wt 0.1 PPG with drilled d rilled solids that means: 0.1 X 2.6 = 0.26 (ppb LGS). 2.6 = specific gravity of LGS. I.E: 0.26 X 42 = 10.92 10. 92 (ppb of pure LGS). Which is too high and will cause a lot of solid problems as mentioned before.
See pages 6-13, 6-14, 6-15, and 6-16.
1. Desan Desander der / Desil Desilter ter Opera Operation tion Tips Tips:: A. Equipment Equipment is fed by a centrifugal pump pump maintaining maintaining a manifold manifold pressure of 35-40 35-40 psi. Excessive pressure contributes to a bladder wear and effects cut point. Excessive pressure may be due to : • Feed lines are plugged. • Distance between equipment pumps and equipment itself is not correct. If pressure is less than 30 psi mean that there is a leak somewhere or equipment equ ipment is not working. In both high and low pressures the efficiency of solid separation is not ok. Proper discharge from the cones is in the form of a conical pressurized spray. Roping may occur when the fluids to be processed has an excessive ex cessive amount of solids present in the mud . Cones discharge may be adjusted by turning the adjustment at the cone apex. If discharge discharge coming out of the cone is like a stream stream (like that causing out of a tap of H2O). this means that cones are highly wearied which will not give a chance for good centrifuging and separating of excess exc ess solids. B. Cones Cones may become become plugged plugged from time time to time and should should be cleaned cleaned by opening opening the adjustm adjustment ent and inserting a welding rod or equivalent from the bottom to dislodge the solids blocking the discharge. C. Continual plugging of cones may be due to the failure of up stream solid control equipment, which should be checked to insure that it’s functional. OR Plugging of cones may be due to incorrect shale shaker mesh screens which allows larger amount of solids to pass into system.(use finer mesh mesh screen after unplugging cones to solve this problem). OR Plugging of cones may be due to those guns in tank before unit is on (stop guns immediately and use normal agitation). D. Weight Weight of discharge discharge must be high as an indicati indication on of getting getting rid of excess solids solids.. If discharge weight is nearly the same or higher a little bit than feed in mud . this means that equipment is not working. Also you can feel the discharge by your hand if it is mud or solids. NB: Cones processes 125-150 % of the flow line GPM.
2. Mu Mud d Cl Clea eane ner: r: The hydrocyclone / screen combination c ombination consists of a bank of desilters which are mounted over a fine mesh vibrating screen. The discard from desilter is processed by the fine screens. Particles are removed by the screen and discarded while the fluid processed through the screen is returned to the active system. Mud cleaner is a fine screen shaker, its primary function is to remove that portion of sand size or larger that passes through rig shaker. NB: Ideally a 200 mesh screen would be desirable on mud cleaner , however 140-150 mesh screens is generally necessary to minimize barite losses.
3. De Dega gass sses es:: • • •
By mean of centrifugal action separates gas + foam from mud. Hydrocyclones ID is ranging from 6”-12”. It process mud immediately from below the sand trap not from the sand trap.
4. Centrifuge: •
Last defend for solids. Can remove solids below 4-6 microns that will not be separated at shakers and pass to the system. These very fine particles have a greater effect on rheology than the coarser particles. Centrifuging will not however eliminate the need for water. But dilution rates will be reduced and a fluid maintenance cost reduction will be expected.
Trend of PV can give an indication of how fast solids concentration is increasing the MBT and solid content and solid content can also be an assistance guide in this determination. • Each type of centrifuge have its own optimum RPM (normal RPM from 1900 to 2200). • Has to be used carefully in weighted mud otherwise will separate barite and affect M.wt. • The reference to make sure that centrifuge is working ok is the discharge weight and weight of flow of processing mud coming out of centrifuge to system. I.E: Must have good flow . processing mud weight must be less than operating mud weight. Charging optimum RPM range of any centrifuge affects the unit efficiency.
SOLID CALCULATION:
CALCULATION USED IN SOLID – CONTROL EVALUATION The following equation is based on the fact that the specific gravity (sg) of the mud is Equal to the sum of the specific gravity times the volume fraction of each component. In this simplified equation, the mud will consist of three basic components: liquid, low-gravity Solids, and high-gravity solids.
Sm = VwSw + VlgSlg + VhgShg NB: Volume of salt water corrected (Vwc) and specific gravity of water (Sw) is obtained from appropriate salt table.
CALCULATE OF LOW GRAVITY SOLIDS AND HIGH GRAVITY SOLIDS VOLUME SOLIDS ANALYSIS: Calculation of low-gravity solids and high-gravity solids from a retort analysis. Correct the retort values and the specific gravity of the water phase by using the salt tables. EQUATION TO GET VOLUME OF LOW GRAVITY SOLIDS
[{ Vw}{Pf}+ {Vss}{Pb} + {Vo}{Po}] – 100{Pm} Vlg = {Pb – Plg} EQUATION TO GET VOLUME OF HIGH GRAVITY SOLIDS
100{Pm} - [{ Vw}{Pf}+ {Vss}{Plg} + {Vo}{Po}] Vb = {Pb – Plg} WHERE: Vlg Vss Vb Vw Po Pm
= volume of low gravity solids solids = volume % of suspended solids = volume of high gravity solids = water fraction fraction corrected for presence of dissolved salt = density of oil = density of mud (spgr)
-
Plg = density of low gravity solids (LGS) = 2.6 Pf = density of water phase corrected for dissolved salts
EXAMPLES OF SOLID CALCULATIONS: IF : M .WT = 14.0 PPG = 1.88 sp .gr Density of weighted material (Pb)== barite = 4.2 & hematite = 5.0 From retort: Vs (volume of solids ) = 28 % Vo (volume of oil) = 8 % Vwr(volume of water) = 64 % CL = 100,000 mg/l (Na CL) 1. Correct Correct retort retort value value for soluble soluble salts salts from from Na CL table table corrected for dissolved salt = 1.111 • Pf = density of water phase corrected • Volume increase factor = 1.059 • Vw ( water fraction corrected for presence of dissolved salt ) = Vwr X volume increase factor = 64 X 1.059 = 67.8 % • Vss (volume percentage of suspended solids) = 100 – Vw – Vo = 100 – 67.8 - 8 = 24.2 % • One bbl of mud = 14 PPG X 42 = 588 ppb • Weight of water = 67.8/100 X PPG of brine water(water of 100,000 mg/l Na CL salt table) X 42 = 67.8/100 X 9.27 X42 = 263 ppb = 8/100 X 7.0 X 42 • Weight of oil = 23 ppb w eight of oil • Calculated weight of solids = weight of mud – weight of water (corrected) – weight = 588 – 263 - 23 = 302 ppb 2. Substitute Substitute in equation equation to to get volume volume of low- gravity gravity solids solids and and high-gravit high-gravity y solids. solids.
[{Vw){Pf}+{Vss}{Pb}+{Vo}{Po}]-100{Pm} Vg = ----------------------- --------------------------------------------------------------------------------------{Pb – Plg} [{67.8}{1.111}+{24.2}{4.2}+{8}{0.84}] –100{1.8} = --------------------------------------------------------------{4.2- 2.6} = 2.3 % LGS
100{Pm}-[{Vw){Pf}+{Vss}{Plg}+{Vo}{Po}] Vb = ----------------------- ------------------------------------------------------------------------------------------{Pb – Plg} 100{1.8}-[{67.8}{1.111}+{24.2}{2.6}+{8}{0.84} = --------------------------------------------------------------
{ 4.2-2.6} = 21.9 % HGS (Barite) •
Percentage of low-gravity solids to total solids 2.3 = ------ X 100 = 9.5 % 24.2
•
Percentage of high-gravity solids to total solids
21.9 = ------ X 100 = 90.5 % 24.2 •
Weight of low-gravity solids . 9.5 = ------ X {2.6 x8.33}X [{24.2/100}X42] 100
•
= 20 pounds Weight of high-gravity solids 90.5 = ------ X {2.4 x8.33}X [{24.2/100}X42] 100 =
•
322 pounds
Fluids concentration TYPE WATER BARITE LGS CARBONATE
SP.GR 1.0 4.2 2.6 2.7
PPG (SP .GR X 8.34 ) 8.3 4 35.028 21.684 22.518
Examples: 1 -fluid -fluid with with 3% LGS, LGS, how how much much concent concentrat ratee in ppb. {3/100} X{910.728} = 27.3 ppb 2
–Fluid –Fluid with with 54.6 54.6 ppb LGS, LGS, how how much conc concent entrat ratee in percen percentag tagee {54.6}/{910.728} X 100 = 6.0 %
3
–Fluid weight 9.2 PPG, PPG, how much much ppb of LGS LGS in un-weig un-weighted hted mud (LGS (LGS % = 7.5%)
PPB(PPG X 42) 350.28 1471.176 910.728 945.756
for unweighted mud: • solids = solids % X [Mud weight – weight of water (8.34)] LGS % = 7.5 (% solids of retort) X ( 9.2 – 8.34 ) • = 6.45 % ( % of corrected solids) LGS ppb = [{6.45}/{100 }}X 910.728 • = 58.7 ppb 4
– On adding 5.5% solids to one o ne bbl of mud free of solids, calculate volume increase
•
5
Volume increase = {5.5}/{100} + 1 = 1.055 bbl
- If If water water = 86 % , oil oil = 10 10 % , soli solids ds = 4 %, MBT = 18 ppb Calculate: % of solids corresponding to one bbl • corrected MBT • corrected solids • total solids in fluid • volume increase by 1 bbl = {4/100} + 1 = 1.04 bbl • corrected solid % in one bbl = {4.0}/{1.04} = 3.85 % • weight of solids = {3.85}/{100}X 910.728 = 35 PPB (of solids} • corrected MBT in one bbl = {18.0}/{1.04} = 17.3 ppb • total corrected drilled solids in ppb (LGS) • LGS in ppb = 17.3 + 35 = 52.3 ppb total LGS % = [{52.3}/{910.728}] X 100 • = 5.75 %
• Mixing liquids of different densities Mass balance equation : 1
-Two phase equation:
{Vt}{Wt} = {V1}{W1} + {V2}{W2} Example: If Vt = 1890 bbl, Mwt (Wt) = 8.8 PPG ,calculate volume of water for for 100 bbls. V1 = volume of water W1= weight of water (8.34 PPG) V2= volume of LGS W2= weight of LGS • 100 X 8.8 = V1 X (8.34) + V2 X 21.7 100 X 8.8 = V1 X (8.34) + {100-V1} X 21.7 1290 = 13.36 V1 V1= 96.6 % V2 = 3.4 % • OR: calculate for total volume:
1890 X 8.8 = 8.34 V1 + {1890 – V1} X 21.7 13.36 V1 = 24471 V1 = 1831.66 V1 % = {1831.66} / {1890 } X 100 = 96.9 % V2 (LGS) = 3.1 % 2
THRE TH REE E PH PHAS ASE E EQ EQUA UATI TION ON::
Vt Wt = V1W1(H2O) + V2W2(LGS) + V3W3(HGS) EXAMPLE: Vt = 100 bbl Wt = 12.5 PPG V1 = 84 ( % or bbl because Vt = 100 ) Solution: • • • • • • • • •
V2 + V3 = 16 % V2 = {16 – V3} W2(LGS) = 21.7 PPG W3(HGS) =35 PPG 100 X 12.5 = {84 X 8.34} + {16 –V3} X 21.7 (wt of LGS) X {V3 X 35(wt of barite)} 13.3 V3 + 1047.76 = 1250 V3 = 202.24 V3 = 15.2 % V2 (LGS) = 16 – 15.2 = 0.8 %
3
-FOU -F OUR R PHA PHASE SE EQ EQUA UATI TIO ON:
Vt Wt = V1W1( WATER) + V2W2( LGS) + V3W3( HGS) + V4W4 (DIESEL) EXAMPLE: IF Vt = 100 • Mwt = 12.8 PPG • V1 = 72 (retort value) • V4 = 10 (retort value) Solution: • • • • •
V2 + V3 V3 = 100 – {72 +10} = 18 V2 = {18 – V3} W2(LGS) = 21.7 PPG W3(HGS) =35 PPG W4(DIESEL) = 7 PPG
• 100 X 12.8 = 72 X 8.34 + {18 – V3}21.7 + V3 X 35 + 10 X 7 • V3 (HGS) = 16.46 % • V2 (LGS) = 1.54 % THREE PHASE MUD WITH SALT: EXAMPLE: • Mwt = 12.1 PPG • Water = 80 % • Solids = 20 % = 141,000 • CL Solution: • From Na CL salt table, salinity of 141.0 k, volume increase = 1.087 • Brine volume = 80 X 1.087 = 86.9 % • Corrected solids = 100 – 86.9 = 13.1 % wa ter corresponding to 141.0 k of CL = 9.6 PPG • From NaCL salt table, adjust density of water • 100 X 12.1 = {86.9 X 9.6} + { 13.1 – V3 }X 21.7 + 35 X V3 • V3 = 6.9 % • V2 = 13.1 (Total corrected solids) – 6.9 • V2 = 6.2 %
ALKALINITY AND PH : •
ALKALINITY IS DEFINED AS THE AVAILABILITY OF H+ IN SOLUTION
•
PH IS A FUNCTION OF DISSOCIATION OF WATER
•
PH NUMBER ARE A FUNCTION OF H+ IONS CONCENTRATION IN GRAM IONIC WEIGHT PER LITER OF MUD. ALKALINITY PROPORTIONAL WITH 1/H+
•
PH = 16 ACIDIC
PH = 7.0 NEUTRAL
PH = 814 ALKALINE
•
IN GENE GENERA RAL L ALKA ALKALI LINE NE MEDI MEDIA A IS THE THE BEST BEST ENVI ENVIRO RONM NMEN ENT T FOR FOR ALL ALL CHEM CHEMIC ICAL AL PRODUCTS TO PERFORM GOOD WHILE DRILLING • PH EXPRESSED AS LOG SCALE (BASE 10) Example: PH OF 9.0 indicates an alkalinity ten times as greater as that of PH of 8.0 . • PH value depending on the concentration of OH group and or CO3 , HCO3 and CO2 in mud As:
IF •
PH =12.0 or higher ======= Mud contaminate with OH group
•
PH =10.0
======= Mud contaminate with OH & CO3
•
PH =9.0 – 10.0
======= Mud contaminate with CO3 group only
•
PH =9.3 - 8.3
======= Mud contaminate with CO3 & HCO3
•
PH =8.3 – 6.0
======= Mud contaminate with HCO3 only
•
PH = 6.0 – 4.3
======= Mud contaminate with HCO3 & CO2
•
PH = 4.3 or lower
======= Mud contaminate with CO2 only.
NB: Using PhPh indicator to test PH value As follows: •
No color ========= PH less than 8.3
•
Light pink color ==== PH 7.5==8.5 • Pink color ======= PH 9.0 =10.0 • Violet color ======= PH more than 10.0 NB: PhPh end point is at PH = 8.3 ALKALINITY OF MUD TEST : (Pm ) • •
•
Prepare 1 ml of mud + 5 ml distilled water + 3 drop PhPh (red pink color) Titrate with H2SO4 acid (N/50)===== end point == colorless indication Pm = Volume of H2SO4 used.
ALKALINITY OF FILTRATE : ( Pf & Mf test) • •
• • •
•
Prepare 1 ml of filtrate filtrate + 2 drop PhPh (red pink color) Titrate with H2SO4 acid (N/50)===== end point == colorless indication Pf = Volume of H2SO4 used Add 2 drops of methyl orange o range indicator (yellowish orange color) Continue titrate with H2SO4 (N/50)===end point == pale red color Mf = total volume of H2SO4 used.
RELATION BETWEEN Pf & Mf: 1. If Mf = Pf or litt little le high higher er : • •
That means mud contaminate with OH ions only Expected to get Ca++ ions contaminate in mud , whenever no CO3 group to precipitate Ca++.
2. If Mf Mf less less than than twi twice ce of Pf: Pf: •
Most of ions CO3 and OH. OH.
3. If MF = TWI TWICE CE Pf Pf:: •
Most of ions are CO3 • High pH related related to CO3 not OH which may causes causes a problem in lignosulphona lignosulphonate te mud Leads no response response for rheological properties. properties.
4. If Mf hig higher her tha than n twi twice ce of Pf: •
Most of ions are CO3 and HCO3. HCO3.
5. If Pf = 0 an and d Mf ve very ry hi high gh:: •
Most of ions are HCO3 only. only.
NB: • Mf is a matter of measuring CO3, HCO3 & CO2 • Pf is a matter of measuring CO3 & OH group. • Pf end point is at PH = 8.3 • Mf end point is at PH = 4.3 • Example: If PH = 9.0 Pf = 0.8 Mf = 1.6
That means high consumption of H+ ions of H2SO4 acid, take the same same quantity of Pf to utilize utilize the filtrate to reach PH = 4.3, So all alkalinity in Pf was from CO3 group. • • • •
Total carbonate = 1220 (Mf – Pf ) Treatment of carbonate contaminate in mud depending on total carbonate value (Mf & Pf ) and type of carbonate . Carbonate contamination treated by adding add ing Lime, or Lime +NaOH or Lime +Gypsum +G ypsum Carbonate contamination treated as follows: HCO3 value X 0.00021 == PPB of Lime (treatment value) CO3 value X 0.00043 == PPB of Lime HCO3 value X 0.002 ==== PPB of NaOH CO3 value X 0.001==== PPB of Gypsum -
Rule of thumb: • CO2 AND H2S are acidic gases • At high PH you have free OH ions in mud deg radation • At high PH we minimize bacterial degradation a s to have some carbonate to react w/ excess Ca ions in mud • Don’t treat carbonate to zero so as • Accepted carbonate in mud is between 500 – 2000 mg/l • A solids problem may look like a CO3 problem. • In case of CO2 treat with lime C<2O + Ca<2OH =(CaCO3 + H2O • In lime mud the influx of CO2& H2S, which are acidic gases gives incorrect Pm/Pf ratio • Solubility of Ca increase with low pH, causing flocculation of mud • Clay or shale becomes highly sensitive to mud in highly pH over 9.0, causing flocculation of mud as the attraction forces between ions increases • Mf value sometimes tend to be higher than actual (false value),this is because some chemicals add ed to mud (such as ,lignosul ,lignosulphonate phonatess , unical , resinex), buffer buffer the pH of the fluid (fix it) it) ,so it takes more amount of H2SO4 to reach pH 4.3. • High pH more than 11.0 may deactivate some polymers, best media pH is between 8.5(10.0. cau ses breakdown (burn) of polymers • Low pH less than 7.0 causes • Ligosulphonate becomes less affective and may cause sever foaming at pH below 8.0,so add caustic • Soda to adjust PH • In lime mud or excess lime Pm becomes higher than Pf as lime lime increases. • To adjust Pm/Pf ratio add lime or caustic soda .
Contaminants : •
Na Cl :
Source : 1. salt do domes . 2. rock ock sa salt beds eds . 3. evap evapor orit itee form format atio ions ns . 4. salt H2O flow . 5. salt salty y mak makee up up wat water er.. Effects : 1. Incr Increa ease se appa appare rent nt visc viscos osit ity y. 2. Incre ncreas asee yield ield poin pointt . 3. Decrease pH pH . 4. Cl- ion will increase in filtration and will decrease P f . 5. Flocc Floccula ulatio tion n follo followe wed d by aggr aggrega egatio tion n of mud mud . 6. Wash of of hole . 7. Chemical foam . Treatment : 1. Dilution . 2. Add thinne thinnerr to reduce reduce appare apparent nt viscosi viscosity, ty, YP, YP, Gel Gel stren strength gth . 3. Add caus caustic tic soda soda (Na (Na OH) OH) to incr increas easee and adju adjust st pH . 4. Add organi organicc thinn thinner er to to reduc reducee filtr filtrati ation on . 5. Analyze Analyze salty make make up water water before before adding to system system otherwis otherwisee it will act act as if we get a salt water water flow flow . 6. To make make sure sure that that there there is no incr increas easee in mud mud weig weight ht . 7. To conv conver ertt to salt salt sat satur urat ated ed mud mud . 8. Any treatmen treatmentt should be done done as soon as possible possible other otherwise wise getting getting a hole hole wash or untreat untreated ed mud may cause cause loose loose control control which might result in moving in salt body into hole getting a pipe stuck . 9. In case case of foams, foams, add add defoame defoamerr (alumin (aluminum um stear stearate ate defoa defoamer) mer) . • Ca SO4 : Source : 1. Gypsum (Ca SO4 2H2O) 2. Anhydrite (Ca SO4 ) . 3. Cap Cap roc rock k of a salt salt dome dome . 4. Make Make up water ter . Effects : 1. Cause Cause floccu flocculat lation ion and aggreg aggregati ation on . 2. Incr Increa ease se app appar aren entt visc viscos osit ity y. 3. Incr Increa ease se YP & gel gel stre streng ngth th . 4. Incr ncreas ease filt filtra rate te . 5. Increase Ca++ ion in mud which cause flocculation . also increase SO4 — content in filtrate which increase hardness . 6. Incr Increa ease se thic thicke keni ning ng of mud mud . Treatment : 1. Add soda ash (Na CO3)with low pH pH or Anhydrox (Ba CO3) or Na HCO 3 with high pH . Na2 CO3 + Ca SO4 = Ca CO3 ↓ +Na2 SO4 . 2. Add thin thinner ner to to reduc reducee viscos viscosity ity and gel gel stren strength gth . 3. Work on thickenin thickening g and filtra filtration tion by adding adding either either CMC CMC , Lignosu Lignosulfona lfonate te . 4. If large large amounts amounts of soda ash is added added , the soluble soluble sodium sodium sulfate sulfate tends tends to build up and and cause (ash (ash gels)whic gels)which h are indicated indicated by High Progressive Gel Strength . Also if HI pH is maintained maintained this too may result in ash ash gels due to formation of Na 2 SO4 . So it is required to a. dilute with H 2O . b. add lime for alkalinity . 5. Prepar Preparee pretrea pretreated ted mud mud with with Q-bro Q-broxin xinee and caust caustic ic soda soda .
6.
Convert to gypsum mud so as Ca SO 4 will have no effect on mud
• Ca (OH)2 Cement : Contamination occurs during : 1. Ceme Cement nt squ squee eeze ze ope opera rati tion on . 2. Poor Poor casi casing ng ceme cement nt job job . 3. Dril Drilli ling ng out out cem cemen entt . 4. Wet (green) (green) cement cement has a greater greater contaminatio contamination n effect effect than hard cement cement because because of increased increased solubility solubility . NB : (Salinity (Salinity + gas + oil) oil) prevent cement cement to get hard. hard. (weak cement job) job) . Effects : 1. Incr Increa ease se appa appare rent nt visc viscos osit ity y. 2. Incr Increa ease se YP YP & gel gel str stren engt gth. h. 3. Increase pH pH . 4. Incr Increa ease se filt filtra rate te . 5. Increase Pf and hardness content of filtrate . Treatment : 1. Reduce pH by adding sodium bicarbonate , this this Na HCO3 will also treat treat the thickness of mud . Caused from from the presence of Ca+ + ions and retain the dispersed – defllocculated condition of mud . NB : 100 lb. Of bicarbonate bicarbonate of soda / 2 cubic cubic feet of hard cement cement . 100 lb. Of bicarbonate of soda / 1 cubic feet of soft cement . This is done to prevent flocculation of clays . 1. If contaminat contamination ion is slight slight , Barafos Barafos is sometimes sometimes used as it will will remove remove calcium calcium ion and reduce reduce pH . NB : Be careful careful of bottom hole temperature temperature . 2. Add organi organicc thinner thinner with with little little or or no caustic caustic soda soda to reduce reduce the the thicke thickening ning of contamina contaminated ted mud mud . Other Divalent ions : Source : EG : a- Magnesium chloride . b- Calcium chloride . c- Magnesium sulfate . 1. In for forma mati tion on wate water r 2. Sea water . 3. Evap Evapor orat atee form format atio ion n. ++ • Mg ion acts like Ca ++ ion contamination . NB : The magnesium can be precipitated precipitated from from solution as magnesium magnesium hydroxide (Mg (OH)2) at a pH above 10 . • H2S Gas : Source : 1. In formation fluids as a result of bacterial action or from from sulfur compounds commonly commonly found in the drilling drilling fluid . 2. Thermal Thermal degradat degradation ion of sulfur contain containing ing drilling drilling fluid fluid additives additives .(EG: .(EG: Lignosulf Lignosulfonat onate) e) . 3. Chemical Chemical reacti reaction on with tool tool joint joint thread thread lubrica lubricants nts that that contain contain sulfur sulfur . Effects : 1. Toxic gas . 2. Corr Corros osio ion n of dri drill ll stri string ng . 3. Decrease pH pH . 4. H2S ⇒ 2H+ + SH+ acidic ion cause corrosion , react with OH- ion in mud causing dehydration of mud and thus flocculation of bentonite and by turn decrease pH and get polymer back to its acidic form and thus do not work . S- cause flocculation of mud and might react with any H+ ion left to give back H 2S . Treatment : 1. Add causti causticc soda soda to to keep keep pH pH above above 10.5 10.5 . 2. Add zinc zinc oxide , zinc zinc carbona carbonate te Zn O + H 2S = ZnS + H2O . 3. Add lime . Lime is reported as lb. /bbl and not ppm . Multiply lb./bbl lime tests constant to get lb./bbl treating agent needed . • At pH 10.5 all but 50 ppm of magnesium has been reacted . • Zinc oxide has less effect on rheological properties in non dispersed systems . • CO2 flocculate mud in case of bentonite mud as it will take OH - ion to give HCO3, also decrease pH . • To get rid of CO 2 add lime Ca(OH)2 = Ca++ + 2OH- . HCO3 + OH- = H2O + CO 3 . Ca++ + CO3-- = CaCO3 .
Chemicals Required to Remove Ionic Contaminations Contaminant (Mg/L)
Ca Ca Ca Mg Mg CO3 CO3 HCO3 HCO3 PO4
X
Factor
=
X X X X X X X X X X
0.00093 0.00074 0.00097 0.00093 0.00116 0.00043 0.001 0.00021 0.002 0.00041
= = = = = = = = = =
Treating Chemical (lb./bbl)
Na2CO3 (soda ash) NaHCO3(Bicarb.) Na2H2P2O7 (SAAP) Na2CO3 (soda ash) NaOH Ca(OH)2 (Lime) CaSO42H2O (Gyps) Ca(OH)2 NaOH Ca(OH)2
Example: Titration of the filtrate shows a calcium level of 650 mg/L. to remove all but approximately 100 10 0 mg/L, treat 550mg/L (650- 100 = 550) of calcium with soda ash. Therefor, soda ash required is approximately 550 X 0.00093 = 0.51 lb./bbl the higher the salinity the lower the pH, the higher the Ca contamination. con tamination. Ca can be
CHEMICAL TREATMENT GUIDE
Gypsum or Anhydrite
cement Lime
Hard water
Hydrogen sulfide
Carbon dioxide (CO2)
Contamination ion Calcium (Ca++)
To remo remove ve add add to to wat water er base base mud mud Soda ash to hold pH or raise it. SAPP to hold pH or reduce it Sodium bicarbonate to hold pH or reduce it.
Amoun Amountt to to add add (lb. (lb./b /bbl bl)) to to rem remov ovee 1 PPM PPM contaminated ion 0.000927 lb./bbl 0.000971 lb./bbl 0.000735 lb./bbl
Calcium Ca++
SAPP Sodium bicarbonate
0.000971 lb./bbl 0.000735 lb./bbl
Calcium (Ca+ + ) Lime (Ca++, OH-)
Sodium bicarbonate
0.000735 lb./bbl
SAPP Sodium bicarbonate
1.5 lb./bbl 1.135 lb./bbl
Magnesium (Mg++) calcium (Ca++)
First: Caustic soda to pH 10.5
0.00116 lb./bbl
Second: Soda ash
0.000928 lb./bbl
Sulfide (S-)
Keep pH above 10.5. add basic zinc oxide, zinc carbonate or lime
0.00123 lb./bbl
Gyp to hold or reduce pH Lime to raise pH Lime to raise pH
0.001 lb./bbl 0.000432 lb./bbl 0.000432 lb./bbl
Carbonate (CO3--) bicarbonate (HCO3-)
0.00805 lb./bbl
NOTE:
Lime is reported as lb./bbl and not PPM. Multiply lb./bbl lime tests constant to get lb./bbl treating agent needed. At pH of 10.5 all but 50 PPM of magnesium has been reacted Zinc oxide has less effect on rheological properties in non-dispersed systems. CO2 flocculate mud in case of bentonite mud as it will take OH - to give HCO3, also decrease pH. To get rid of CO2 add lime Ca(OH)2. Ca+2 + 2 OHHCO3 + OH- = H2O + CO3 Ca+2 + CO3-- = CaCO3
TROUBLE SHOOTING GUIDE Problems
Weight too low
Barite Weight
Viscosity
MBT
Normal or high
Low Density Solids
Calcium Content
Normal Normal
Add barite.
Normal _
Normal
Low
High
High
High
Normal
Dilute, add barite, XC polymer and polyac.
Normal
Normal
High
Normal
Normalhigh
Normalhigh
High
Normal
Dilute w/ H2O, add prehydrated bentonite +XC polymer if needed to maintain viscosity. Dilute w/ H2O, add XC polymer & polyac.
Normal
Normal
Add prehydrated bentonite + XC polymer
Normal
Normal
Normal
MBT may be due drilled solids-so dilute or remove solids, Add prehydrated bentonite + XC polymer
High
Normal
Normal
Dilute or remove solids, add XC polymer & polyac.
Normal
Normal
Normal
Insufficient amount of XC polymer + barite. Add both.
Normal
Normal
High High pH
Normal
Low
Normal
Normal
Before drilling cement, pre treat w/ sodium bicarbonate rather than soda ash. Use soda ash only w/ normal drilling. Add prehydrated bentonite + XC polymer & polyac.
Normalhigh
Normal
Normal
High
Normal
Normal
Normal
Normal
_ Normal _
Weight too high
Treatment
Low Normal _
Viscosity too Normal low Normal
_
Normal Normal
_
Normal Normal
_
Normal
Viscosity too Normal high
_
Normal Normal
High temp. High press.
Normal
Fluid loss too high
Normal
Low
_
Normal
Normal Normal
Normal
Remove C++ by sodium bicarbonate rather than soda ash. Add 100-150 PPM Ca to suppress the yield of bent. This well allow more bent. to be added to the mud for better particle size distribution without excessive viscosity.
NB: Gel ∝ PV, to break down gel, dilute (fresh water + caustic soda + spersene. Replace mud. The addition of water should be slow.
CHEMICAL TEST (WBM) • Salinity: CL : 1ml of filtrate + ph.ph if pink add 0.02 H2SO4 colorless. 1 ml of filtrate + 5-10 drops potassium chromate (yellow) # Ag NO 3 (end point orange red ppt). CL = volume of Ag NO3 X 10000 . • KCL : 6 ml of filtrat filtratee + 3 ml sodium perchlorate perchlorate (centri (centrifuge) fuge) ppt of of potassium potassium perchlor perchlorate, ate, ml ppt with with standard standard curve. •
Hardness:
*
Ca++
1ml of filtrate + 10 drops of Na OH(1N) + Caliver 2 indicator # EDTA end point violet color. Volume of EDTA X 400 = Ca++, Let volume of EDTA = A.
pink.
* Mg++
1 ml of filtrate + 2-5 drops Buffer solution (Ammonia) + Erichrom black indicator (pink). # EDTA end point sky blue. Let volume of EDTA = B ++ Mg = (B-A) X 243.2 •
Alkalinity of Mud:
* Pm:
1 ml of mud + 5 ml distilled water + 3 drops ph.ph (Red – Pink). # H2SO4 (N 50) end point colorless. Pm = volume of H2SO4. •
Alkalinity of Filtrate: • Pf : 1 ml of filtrate + 2 drops of ph.ph (pink). # H2SO4 (N 50) end pint colorless • Mf: Add 2 drops of Methyl orange (yellow orange). # H2SO4 (N 50) end pint pale red. NB: Very Important: 1. To increase pH add caustic soda. 2. To decrease pH add dilution. 3. To treat flocculation dilution + thinners. 4. To treat foams add defoamer. 5. To treat viscosity dilution + thinners. 6. To treat water loss add filtration control agents.
7. To treat Ca++ add soda ash. ++ 8. To treat Mg add Ca CO3. 9. To treat CO3, HCO3, PO4 add lime. To Measure PV , YP and Gel Strength: • B mean of apparatus of Rheology (viscometer): 1. Fill Fill cup cup wit with h mud. mud. 2. Fit agitator. 3. Adjust Adjust apparatus apparatus to 600 RPM and then allow allow agitation. agitation. Take reading reading on gauge. 4. Adjust Adjust apparatus apparatus to 300 RPM and then allow allow agitation. agitation. Take reading reading on gauge. 5. PV = Read Reading ing 600 600 – Readi Reading ng 300. 300. 6. YP = Rea Readi ding ng 300 300 – PV. PV. 7. Adjust Adjust apparatus apparatus to 600 RPM again and then then allow agitati agitation on for few minutes. minutes. 8. Then adjust adjust apparatus apparatus to 3 RPM. Put on , after after waiting waiting for 10 sec. Take maximum maximum reading reading to be first first reading for gel. 9. Then adjust adjust apparatus apparatus again to 600 RPM , allow allow agitation agitation for few minutes minutes.. 1 0. Wait this time 10 minutes. 11. Then Then adju adjust st to 3 RPM RPM,, all allow ow agita agitati tion on and and tak takee max maxim imum um read readin ing g to to be be seco second nd read readin ing g for for gel gel strength. To Measure Water Loss and Filter Cake: • By mean of apparatus: 1. Fit bottom bottom end of cell cell to cell after after putting putting a filter filter paper paper covered covered by a rubber o-seal o-seal.. 2. Fit cell cell wit with h mud enou enough gh for for half half an hour. hour. 3. Fit cell cell in in place place over over a graduat graduated ed cylin cylinder der.. 4. Fit Fit top top par partt of appar apparat atus us.. 5. Apply Apply pres pressu sure re 100 psi. psi. 6. Mud starts starts loosing loosing water water collected collected in graduate graduated d cylinder. cylinder. 7. If takin taking g reading reading after after 7 ½ minut minutes es multip multiply ly by 2. 8. If not continue continue ½ an an hour you will will get the same same reading. reading. 9. Take filter filter paper paper out. out. Clean Clean filter filter paper from all all above above cake, measure measure cake. cake. NB: Relation between water loss and cake:
Water loss Wat oss (m (ml) Above 20 F/8 T/ 20 Less than 8 2-3
Cake Cake (cak (cake/ e/32 32)) 3-4 2 1 1/2
To Measure Solids and Oil %: • By mean of apparatus: 1. Fill Fill cell cell with with mud mud.. 2. Put Put in bar barrel rel. 3. Fit Fit all all toge togeth ther er.. 4. Place Place a gradu graduate ated d cylind cylinder er under under cell cell.. 5. Appl pply hea heat. 6. All fluids fluids will will evaporit evaporitee and condense condense to be be collected collected in cylin cylinder. der. 7. When finish, finish, the cylinder cylinder will will still still having an empty part part which will will be correspondi corresponding ng to solids solids in mud by % reading remaining empty to filled part. 8. Also Also read read part part contain containing ing oil oil to be oil oil perce percent nt %. Test MBT:
Add 2 ml of mud + 8 ml of deionized H2O + 15 ml of 3 % hydrogen peroxide + 0.5 ml of sulfuric acid. 2. Boil Boil gent gently ly for for 10 10 min min.. 3. Dilute Dilute to to about about 50 ml with with dist distil illed led water water.. 4. Add Methylen Methylenee blue solution solution about about 0.5 ml ml and steer steer for about 30 sec. 5. While While the solids solids are still still suspended, suspended, remove remove one drop drop of liquid liquid and place place on a filter filter paper. paper. 6. The end point point is reached reached when the the dye appears appears as a blue ring ring surrounding surrounding the the dyed solids. solids. 7. Shake or steer steer for two minutes minutes and place place another drop drop on the filter filter paper. If the the blue ring is again again evident, evident, the end point is reached. If not, not, continue as before until a drop taken after shaking shaking two minutes shows the the blue dye. ML of Methylene blue 8. Meth Methyl ylene ene blue blue capa capaci city ty = . ML of mud 9. Where : Bentonite equivalent (lb./bbl mud) = 5 X Methylene blue capacity. (Kg/m3 mud) = 14.25 X Methylene blue capacity. capacity. NB: drilling mud frequently contains substances in addition to bentonite that adsorb Methylene Methylene blue, treatment with hydrogen peroxide is intended to remove the effect of organic materials such as CMC, Polyacrylates, Lignosulfonate and Lignite. 1.
SHALE FACTOR:
Clay types have different cation exchange capacities (CEC) and consequently different adsorption capacities. It was also shown shown that Na montmorillon montmorillonite ite clay will undergo diagensis diagensis to illite with the increasing increasing of temperatu temperature re by the ionic ionic exchange of K ions instead of Na ions In order for diagenesis to proceed, water must be flushed out from clays. If exchange cations K are not available to exchange Na montimorillonite clay will lose its water, but will not convert to illite thus if this type of clay is drilled with a water-based mud, the clay will hydrate and causes drilling problems. The cation exchange capacity (CEC) will will decrease as clays convert from montimorillonite montimorillonite type (with temperature and thus with depth and pressure). Pure montimorillonite clays show a CEC of 100 meq\100gm. Pure illites (shows no swelling characteristics) have a CEC generally between 10&40 meq\100gm. Kaolinites have a CEC CEC of approximately 10 meq\100gm. meq\100gm. In general bentonite and montimorillonite have an affinity for water. NB, the clay clay /shale zones will will have an affinity affinity for water water in an amount proportional proportional to the montimorillonite montimorillonite content.
PORE PRESSURE:
There Some Factors That Affects The Estimated Pore Pressure: 1. 2. 3. 4. 5. 6.
Mud weigh weightt and backgr backgroun ound d gas relat relation ionshi ship. p. Gas cu cut mu mud. Cutt Cuttin ing g chara charact cter er.. Hole Hole cond condit itio ion. n. Tem Temper peratur ature. e. Dex.
1. Mud wei weight ght / backg backgrou round nd gas: gas: • When the pumping stops , the hydrostatic pressure could be below the formation pressure. • When connection gas occurs , that means we lost the ECD margin. • It is normal to drill with normal mud weight and having formation gas coming out (FBG). NB: The gas coming out depend on porosity, permeability, gas saturation and ∆ P. ∆ P = (W X D X 0.0519) – (FBG X D 0.0519). W = mud weight . D = depth. ∆ P should be positive while drilling. If ∆ P is negative a continuos influx occur showing by high background gas and gas cut mud while circulation. C.G. Trip Gas. Must be taken in our consideration. Formation Type.
2. Ga Gass Cut Cut Mu Mud: d: In shallow wells In deep wells
great problem. could be with no problem
Gv = { (d/2H) X (3.14 ROP/60) X φ X Sg } X 7.48 Gv = gas rate. d= hole diameter. Sg = gas saturation. Gas @ atmospheric pressure = 14. 7 psi. Gva = Gv X (P/14.7). Mud flow (GPM) W1 = X W2(uncut mud). Mud(GPM)+ Gas (GPM) W1 –W2 Pressure reduction( ∆ P) = 14.7
[
3.53 X W2 X D
] In [ W1
] 1000
D = depth of gas zone.
3. Cut Cuttin ting g Characte Characters rs (Caving (Cavings) s) (Cvg): (Cvg): The more the caving the more unsuitability of the well which indicate that h ole is under balance.
4. Ho Hole le Co Cond ndit itio ion: n: If the following conditions occur: • Caving occur. • Over pull and drag while tripping. • Torque while drilling.
•
Connection gas and trip gas increases. • Pit level is increasing (I.E formation fluids are coming out to well). This indicates that ECD margin is balance or below the formation pressure and we are taking or about to take a kick. NB: Watch ROP it will increase and P.P. also will increase. NB: Over pull could occur because of : a. Over pressu pressured red zone zone whic which h cause cause swell swelling ing . b. Swelling of shale due to absorption of water. c. Due to ledge ledgess or or dog dog legs legs.. This could be solved by increasing the mud weight. Or by jarring, or by back reaming, or by an acid job (in case of carbonates), or by pumping fresh water in case of salt.
5. Sh Shal alee Dens Densit ity: y: Under normal conditions shale density increases with depth. N.B: Any accessories will cause increase in shale density (I.E silty, silty, pyritic, calc content …. Etc.). If shale density decreases while increasing of depth, this indicates high pore pressure zone.
6. Te Temp mper erat atur ure: e: Increases with depth. NB: Any sudden drop in temperature is an indication of a pressure p ressure zone. This drop in temperature at or before pressure zone. TYPICAL DENSITIES Type S.S L.S DOLO ANHY SALT GYPSUM CLAY FRESH H2O SALTY H2O OIL
Matrix Density 2 .6 5 2 .7 1 2.8 7 2 .9 8 2.0 3 2 .3 5 2.7 – 2.8 1 1. 1 5 0. 8
7. D Ex Expo pone nen nt: It is affected by RPM, tooth effect, drilling hydraulics (P.P, pump flow, nozzles and mud rheology) matrix stress and formation compaction. The DXC a correlation of drilling parameters with ROP in shales
Soft formation (porous & permeable)
Hard formation (compact) Trend
PORE PRESSURE TRANSMISSION:
As well known that shale rock have no permeability, but shale as beds has a sort of unextended cracks which acts as secondary permeability. permeability. As a rule of thumb the hydrostatic pressure of mud column acts against the formation to control the formation pressure. But by time part of the hydrostatic pressure migrate into the formation through its pores (degree of migration depends on porosity &permeability of the rock ). (The (The filter filter cake acts to prevent prevent this transmissio transmission n of pressure into formation formation , offcoarse offcoarse if this filter filter cake is a good rigid impermeable cake). In case of shale and as there is no possibility of formation of filter cake the shales is directly exposed to hole and thus to hydrostatic head of mud. So this transmission is possible through its cake if present. By time this transmitted pressure will accumulate inside the shale rock and acts as a formation pressure in a reverse way against the hydrostatic mud column together with original formation pressure. If the summation of both formation and transmitted pressures exceeds the hydrostatic mud column or ECD the formation will acts as over pressurized zone, and caving occurs together with other bore hole problems as mentioned in pressure control section and shale bore hole problems problems section.
FORMATION PRESSURE : All sedimentary rocks are porous to some degree. These void spaces within a rock grains are filled with fluids (liquid or gas or combination of both). both). These fluids within pore spaces exhibit a sort of pressure known as PORE PRESSURE. PRESSURE. Pore pressures are equivalent to the average hydrostatic pressure exerted by the fluid contained in the pore spaces from water table (on shore) and sea level (off shore).
PORE PRESSURE GRADIENT : Is the pressure per unit depth , which is refereed to water table on shore and sea level off shore (pressure gradient =0.0519*ppg).
EG: off shore Depth = 1000 ft Sea water density = 8.6 ppg Distance between RKB to sea level =60 ft Actual pore pressure gradient = (1000 – 60) * 0.0519 * 8.6 = (420 psi) (0.446 psi/ft) EG : on shore Depth = 1000 ft Water density = 8.34 ppg Depth of water table = (220 ft (from RKB ) Air gap = 30 ft (between RKB & surface) Actual pore pressure gradient = (1000 – 220) * 8.34 * 0.0519 = (338 psi) (0.433 psi/ft) NB : Actual Actual pore pressure =depth(from =depth(from sea level level or water table) table) * pore water water density(ppg) density(ppg) *0.0519 But while drilling pore pressure is referenced to the flow line not to water table(on shore) or sea level(off shore). Thereby due to the difference in height between flow line and the water table(on shore) and flow line and sea level(off shore), so the measured gradients during drilling will not be the actual actual pore pressure gradients , but will represent represent the hydrostatic pressure of the drilling fluid fluid required to balance the formation pressure at the depth from the flow line. This can be termed as NORMAL FORMAT FORMATION ION BALANCE GRADIENT . From EG 1 : If the distance from RKB to flow line = 5 ft Calculated pore pressure gradient form flow line (hydrostatic pressure of drilling fluid required to balance the formation pressure at 1000 ft from flow line ) = 420 / [ (1000-5) * 0.0519 ] =8.07 PPG (0.419 psi / ft ). From EG 2 : Calculated pore pressure gradient from flow line = 338 / (995 * 0.0519 ) =6.5 PPG (0.338 psi /ft ). PS : Apply on greater depth of 3000 ft2 For EG 1 : Actual pore pressure gradient = ( 300 – 60 ) * 0.0519 * 8.6 = 1312 psi (0.446 psi / ft ) pore pressure gradient gradient from flow flow line=1312 /[ ( 3000-5 ) * 0.0519 ] =8.44PPG (0.438 psi /ft ) For EG 2 : Actual pore pressure gradient = (300-220) * 0.0519 * 8.34 =1203psi (0.433psi/ft) pore pressure gradient gradient from flow flow line=1203 / (2995 (2995 * 0..0519)
=7.74PPG (0.402psi/ft) Apply on greater depth 10000 ft . For EG 1 : Actual pore pressure gradient
= (10000-6) * 0.0519 * 8.6 =4437 (0.446psi / ft) Pore pressure gradient from flow line=4437/[ (10000-5) * 0.0519 ] =8.55PPG (0.444 psi/ft) For EG 2 : Actual pore pressure gradient =(10000-220) * 0.0519 * 8.34 =4302 (0.433 psi/ft). Pore pressure gradient from flow line=4302 / (9780 * 0.0519) = 8.48PPG 8.48PPG (044 psi/ft) psi/ft) . Its apparent that with depth increase the normal FBG will approach the actual pore pressure. But at shallow depths the differences between actual pore pressure and normal FBG are extremely remarkable . Since there no water – base mud dose have a density of 6.5 or 8.1 PPG . So drilling with the least available water – base mud densities (8.6 –8.8PPG) in shallow holes will approach or exceeds the fracture pressure of the formations resulting lost circulation and no returns . Since the pore pressure is not constant from surface all the way down bore hole , but actually increases with increase of depth. The gradient as measured from the flow line is termed FORMATION BALANCE GRADIENT (FBG) and this is precisely equal to static equivalent mud density (Eq M wt ) required in the bore hole to balance formation pore pressure.(so the terms may be used interchangeably). FBG is always less than pore pressure gradient . PS : Formation pressure = pressure on the standpipe gauge (after stopping circulation and closing chock) +hydrostatic pressure of mud column in the drill pipe (as mud inside drill pipe will be normally not contaminated). Formation pressure = SIDP +(M wt * TVD * 0.0519) . Controll Controlling ing the formatio formation n pressure pressure is one of the primary primary functions functions of drilling fluids fluids that is mainly controlled controlled by the hydrostati hydrostaticc pressure exerted by the fluid column in the annulus ,whenever the formation pressure exceeds the total hydrostatic pressure of the drilling fluid ,the formation fluids will invade the well bore causing a kick .
OVERBURDEN PRESSURE : Overburden is that pressure resulting from the combination between those pressures resulting from overburden weight of the rock grins and pore pressure resulting from fluid content in pore spaces. Po =Pf +Pc Where Po = overburden pressure gradient (psi/ft) Pf = fluid pressure gradient (psi/ft) Pc = rock grains pressure gradient (psi/ft) EG : Rock grain density = 2.6 gm/cm3 Pore fluid density =1.07 gm/cm3 Porosity =34% 2.65 * (66/100) = 1.75 gm/cm3 1.07* (34/100) = 0.36 gm/cm3 Average overburden density of this rock =1.75+0.36 =2.11gm/cm3 =2.11*8.34*0.519 =0.92 psi/ft Normal overburden overburden pressure varies varies from approximately approximately 0.84 psi/ft near the surface surface to 1.0 psi/ft @20000 ft.
NORMAL FORMATION PRESSURE : When a formation is deposited , the formation keeps some fluids in its pores (mostly water) until being exposed to another overlying sedimentation which exerts a sort of compression pressure on underlying sediments causing escape of some underlying formation fluids fluids due to that compress compression ion force on its pore spaces , the amount of escaped fluids fluids depends on degree of compaction compaction of rock(resulting from above compression force) also its permeability. If the amount of escaped fluids off formation are equivalent to overburden pressure and the depth , also corresponding to equivalent temperature and pressure at that depth. So the formation keeps a normal pressure . Normal Formation Pressures : # Marine basins = 0.465 psi/ft =9.0 PPG with salinity of 80000 mg / l CL. #Island areas = 0.433 psi/ft = 8.34 PPG .
ABNORMAL FORMATION PRESSURES :
When fluids are sealed within a formation (due to impermeability ) and unable to escape ,they then support apart of the weight of the overburden . As the depth increase the overburden load increases and accordingly the formation pressure increases . Also increase of temperature will lead to abnormal pressure. Causes For Abnormal Pressure : 1- Rapid Rapid sedimentati sedimentation on rates accompa accompanied nied by thick and low – permeab permeability ility shale shale sections. sections. 2- Tectonic Tectonic activit activities ies such such as salt intrus intrusions ions and and anticline anticline folds. folds. 3- Diagenet Diagenetic ic alterations alterations such as conversion conversion of anhydrite anhydrite to gypsum gypsum . The resulting resulting volume increase increase could could generate substanti substantial al pressure increase increase within a sealed sealed zone. 4- Formations that that have been been charged with with water from surroundings, surroundings, and this this water was captured captured inside the formations. How to Recognize Abnormal Pressure Zones : Abnormal pressure zones are usually accompanied by under compacted shales. This change in shale characteristics generally results in : 1- Increa Increase se in normal normal porosi porosity ty.. 2- Increase Increase in forma formation tion fluid fluid content content and and change change in formatio formation n density. density. 3- Increa Increase se in in shale shale conduc conductiv tivity ity..
METHODS OF FORMATION PRESSURE PREDICTION : 1- Seismic data the area to be drilled : Since the abnormally pressured zones have not compacted normally with depth and hence its porosity is high ,together with presence of high content of gas or fluid occupied within its pore spaces, so the velocity of sound waves traveling through these formations is reduced . I.e.: very high adsorptive function to sound waves ends thus very low reflective function to sound waves traveling through it. This method method is highly highly useful useful in detecting detecting shallow shallow gas sands, sands, but more difficult difficult to detect detect deeper deeper gas.(need gas.(need to have more geologic information about area from nearby offset wells). 2- Electric log analysis: a- Conductivity Logs : Abnormally pressured zones can be predicted by analyzing changes in shales conductivity recorded on conduction logs. This is done by taking several points of shale conductivity Vs depth. Then draw the best straight straight line of shale conductivity. Any shift from that line indicates an abnormal pressure zone . Then calculate the ratio of shale conductivity observed to the normal conductivity of that shale, that was suppose to fall on guide line if normal situation Like that we can indicate the equivalent formation pressure and thus the equivalent fluid density to drill with. This varies from one area to another. EG : At depth 13000ft Observed shale shale conductivity conductivity = 1670 Normal shale conductivity = 630 So the ratio of observed conductivity =1670 /630 /630 = 2.65 DIGRAM This 2.65 is corresponding to a formation pressure of :16.1 PPG in 12.9 PPG 12.1PPG 13.5 PPG
TABLE
B- Son onic ic Log ogss :
South South Louisiana Louisiana in Texas GULF Coast in North Sea in South China Sea
Sonic logs measure transit time of sound for a fixed distance through formations(the same as the seismic logs information). Interval transit time (micro seconds per foot) decreases as the formation porosity decrease because a density material transmits sound waves at a higher velocity than a less dense material. Porosity generally decreases at near linear rate as a function of depth in normally compacted shales. A plot of shale travel time is normally near a straight line with graduated reduction in travel time as a function of depth . Increased shale porosity (which usually indicates a change in compaction and abnormal pressure)would produce an increase in shale travel time. Plot a graph of shale transit time versus depth, any shift from normal compaction trend of shale indicates abnormal pressure zone . EG : At depth 13000 ft Observed transit time = 130 (micro sec/ft) Normal transit time = 95 (micro sec/ft) Difference = 35 (micro sec/ft) Which is equivalent to a pore pressure of 15.8 PPG U.S Gulf Coast 14.75PPG South Texas Gulf Coast 14.25PPG West Texas 13.15PPG North Sea 13.6 PPG South China Sea
DIAGRAM & TABLE
SOME SUG SOME SUGGES GESTION TIONS S FOR SELECTI SELECTING NG THE SHA SHALE LE DATA PIONTS PIONTS POI POINTS NTS TO BE USED IN FOR FORMAT MATION ION PRESSURE PREDICTION ARE :
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Select clean clean shales in intervals of low spontaneous spontaneous potential (SP) deflection deflection and uniform uniform conductivity conductivity or sonic sonic readings Shales selected selected for data data points should should be at least 20 ft thick with with points obtained obtained from the the center of the section if possible Shales Shales stringers stringers within within massive massive sand sections sections tend tend to exhibit high high unreliable unreliable readings readings Avoid shale readings immediately immediately above known gas sand. sand. These readings will will characteristically characteristically display high unreliable unreliable values If available, available, the caliper caliper survey survey should be scanned scanned for excessive excessive hole enlargem enlargement, ent, excessive excessive enlarge enlargement ment can create create a skip in signal on sonic logs and lead to erroneous data . Avoid plotting plotting silty or limey shales shales by inspecting inspecting the SP curve. Minimum Minimum SP values will result in more reliable reliable data .
DRILLING PARAMETERS USED TO INDICATE AN ABNORMAL PRESSURE ZONE : 1- RATE OF PENETRATION : The increase of ROP indicates abnormal pressure zone . A rule of thumb is that a uniform decrease in ROP of shales normally occurs with depth. This decrease in ROP results from the increase of compaction and density of the shales. To understand the action action during drilling , when when a bits tooth penetrates penetrates hard formation it forms forms a cone of crushed rock immediately immediately beneath the tooth. The formation of cracks alone will not make a hole, so the cuttings must be removed as they are formed. The most effective force for the removal of cuttings is high velocity jetting by the bit. (PS : In plastic formations the material will be gauged rather than crushed). The ease with which cuttings are removed (and hence picking up ROP )depends upon the differential pressure across bottom. Differential pressure = is the difference between bottom hole circulating pressure (ECD) formation pore pressure (or formation balance gradient gradient FBG ) If circulating pressure is much larger than formation pressure (overbalance) cuttings will be held down against bottom by the excess differential differential pressure . As the overbalance is decreased , these effects are reduced , cuttings will be removed easily and ROP will increase . In drilling overpressured zone the formation pressure is sufficiently exceeding the circulating pressure (underbalance) ,the mud filter cake ceases to form, and the cuttings are forced away from the formation , and thus increase in ROP occurs .
PS : It can be seen that the ROP can be controlled by differential pressure alone. In most drilling situations it is desirable to maintain the mud density slightly higher than FBG (formation pressure PPG). The resulting differential pressure can be calculated as follows = (W * D * 0.0519 ) – ( FBG * D * 0.0519 ) = P where W = mud density PPG D = depth ft FBG = formation formation pressure gradient gradient PPG P = differential pressure NB 1: Substituting ECD for W gives differential pressure while drilling . NB 2 : P should be positive during all drilling operations. NB 3 : If FBG > hydrostatic pressure , influx occurs . Generally we can not count on ROP only as there are other parameters affects the ROP such as: A – Lithology changes B – Bit weight C- Bit type D –Bit condition E – Rotary speed F –Drilling fluid properties G –Hydraulics (bottom hole cleaning) 2 - VARINACE IN SHAPE AND SIZE OF SHALE CUTTINGS : Shale cuttings from an abnormally pressured zone are larger than those from a normally pressure zone. They are characterized by sharp and angular edges and needle like shape , while normal pressured cuttings are generally small and flat with rounded edges . The variables which determine the size and shape of shale cuttings are : a- Mineralog Mineralogical ical , chemic chemical al and and physi physical cal propertie propertiess . b- Type of drilling fluid . c- Hole ole geo geom metry etry . d- Down Down hole hole agit agitat atio ion n. 3 - CHANGE IN ROTARY TORQUE : During normal drilling operation , rotary torque gradually increase with depth due to the effect of wall contact of the drillstring on the well bore also the action of formation on bit rotation Any abrupt changes from this trend indicates :(a twist of in the drill string , a locked cone on the bit , a wash out in the drill string , a change in formation pressure) Increase of pre pressure causes larger amount shale cuttings to come into the well bore ,and the bit teeth will take larger bites into the formation. The increased amount of shale tends to stick or impede bit rotation. Rotary torque can not be an indicator for abnormal zones in deviated holes. 4 – CHANGE IN DRAG AND OVERPULL : When drilling in a balanced or near balanced situation, an increase in drag and over pull can occur while making a connection in abnormally pressured zone. This increase in over pull and drag is due to : a- Plastic nature of some pressured pressured shales, shales, which may cause close of shale around around the drillcollars and bit. b- Swelling action action of shale c- Extra Extra pressured pressured shale shale cuttings cuttings which which enter the the well pore pore when keeping keeping abnorma abnormall pressure. pressure. 5 - SHALE DENSITY : Shales which are normally pressured have undergone normal compaction and thus densities increase uniformly with depth, this uniform increase allows shale density to be predicted. Any significant reduction in shale density (due to improper compaction and occupying of more fluids than usual) indicates an overpressured zone. 6 - INCREASE IN CHLORIDE IONS IONS IN MUD ABOVE 10,000 mg/l : 7 - DECREASE OF FLOWLINE TEMPERATURE : A normal trend for flow line temperature should be plotted or recorded . Any significant decrease in flow line temperature (6F or above)indicates overpressured zone. But still this parameter has to be compared with some other parameters be positive of presence of an overpressured zone . 8-
GAS CONT GAS CONTEN ENT T OF DRI DRILL LLING ING FLU FLUID ID : Increase of gas content of drilling fluid was recommended an indicator for detecting abnormal pressured zones.
Since the gas cutting is not always a result of an underbalance condition, so correct interpretation of gas cutting trends is recommended . Also a trend for background gas and connection gas is recommended . So as when having any abnormal significant increase in gas it can be referred to presence of an abnormal pressured zone . # Gas may be entrained in mud column as a result of the following conditions : a - When a formation containing gas is drilled, and while circulating circulating cuttings containing gas up the hole , gas in these drilled particles expanded expanded and released to the the drilling fluid fluid system causing causing cut in the mud weight . in such cases , increasing M.wt will not stop the the gas cutting. This condition can be verified by reducing drilling rate or by stopping drilling and circulating bottoms up. b- While drilling drilling a pressured formation formation the differential differential pressure pressure between the ECD ECD and formation formation pressure is reduced reduced to be very close. I.e. : ECD is very slightly higher than formation. But when stopping circulation the static hydrostatic fluid column pressure is nearly equal or even less than formation . So on making a connection or trip the piston effect of upward pipe movement can swap formation gases and fluids into the well bore causing cut in in M.wt especially especially gas which will will expand on circulating circulating up causing causing gas cut. Ps : If differential pressure increases but from negative side . I.e. formation become > hydrostatic pressure So the influx activity of the formation content bore hole increases and might exceed to cause a kick. # To detect the amount of gas entering the mud system as follows : Gv =(d/24) * (#*R/60) *porosity *Sg * 7.48 Where Gv = rate of gas entering the mud mud system at reservoir pressure pressure (gal/min) R = rate of penetration penetration (ft/hr) (ft/hr) d = hole diameter (inch) Sg = gas saturation EG : If d =8.5 porosity = 25% R = 85 Sg = 70% With a reservoir pressure at 15,000ft of 7,000 psi Gv = (8.5/24) (3.14*85/60) * 0.25 * 0.7 * 7.48 = 0.731 GPM @7,000 ft the gas volume each minute at atmospheric pressure(14.7 pressure(14.7 psi) using ideal gas low (neglecting temperature effect) is : Gva =Gv *(P/14.7) =0.731 *(7,000/14.7) = 348 GPM @ atmospheric pressure when the gas reaches the surface the volume of gas flowing with mud is about 350 GPM. If the normal flow of mud is 280 GPM using a M.wt of 9.2 PPG , the gas mixed with mud at that GPM will result in a mud density of : W1 =[GPM (mud) / GPM (mud) + GPM (gas)] *W2 Where W1 =gas =gas cut cut mud density PPG W2= uncut mud density PPG W1 =[280 / (280+350)] * 9.2 = 4.1 PPG. NB : Increasing Increasing the mud density density will not reduce reduce gas cutting as the hydrostatic hydrostatic pressure of 9.2 PPG mud @ 15,000 ft is7162 psi psi . i.e., 162 psi greater than reservoir pore pressure. The pressure reduction caused by mud cutting : P = 14.7 * [(W2-W1) / W1] * Ln [(3.53*W2*D) / 1,000] P = pressure reduction caused by mud cutting psi W1= gas cut mud mud density at the flow line PPG W2=uncut mud density PPG D =depth of gas zone ft Using information from previous example : P =14.7[(9.2-4.1) / 4.1] * Ln[(3.53*9.2*15,000) / 1,000 ] = 113 psi So the actual mud gradient @ 15,000 ft is : W = [hydrostatic pressure – P ] / D * 0.0519 = [7162 – 113] / 15,000 *0.0519 = 9.0+ ppg PS : The decrease in bottom pressure in deep wells is small as shown in previous example, But in shallow wells it is a major problem . EG : Hole diameter = 12.25” Drilling rate = 500 ft/hr Depth = 1,000 ft Formation has 30 % porosity Formation has 70 % gas saturation. Formation pressure = 467 psi (9 PPG).
M.wt = 9.2 PPG Pump rate = 450 GPM Amount of gas entering the mud system =(12.25/ 24) *[ (3.14 * 500) / 60 ] * 0.3*0.7*7.48 = 10.7 GPM @ 467 psi. Gas volume each minute at atmospheric pressure = 10.7*[467/14.7]= 340 GPM. The resultant mud density = [450/(450+340)] * 9.2 = 5.2 PPG.
Thus the pressure reduction at 1,000 ft P =14.7*[(9.2-5.2)/5.2] * Ln [(3.53*9.2*1,000)/1,000] [(3.53*9.2*1,000)/1,000] = 39 psi although the pressure reduction appears to small, only 39 psi, but the resultant mud gradient @ 1,000 ft = [9.2*1,000*0.0519]-39 =438 psi [438 / (1000*0.0519)] = 8.4 PPG The mud gradient is reduced from 9.2 PPG to 8.4 PPG by a reduction of 39 psi @ 1,000 ft. If formation pressure gradient gradient is 9.0 PPG @ 1,000 ft, the well will kick if this situation is permitted permitted to occur. NB : Gas cut mud @ shallow depths may be extremely hazardous as a severe kick and loss of well control can result ! These calculations do not take into account the effect of temperature and compressibility has a small effect on gas expansion when compared to effect of pressure . But due to difficulty of estimating formation temperature and obtaining realistic values for gas compressibility . The calculation only takes pressure into account. On surface the temperature effect is insignificant . NB1: Circulating gas out without controlling gas expansion causes reduction in annulus hydrostatic column and thus cause disturbance in differential differential pressure (formation pressure comes to be >hydrostatic pressure ) as pervasively mentioned causing more gas influx into the well bore leading to gas kick . NB 2 : Deferential pressure is one of the major factors that affect the amount of gas that enters the mud Other factors effecting the gas influx are porosity and permeability of the formation and also gas saturation. NB 3 : Negative differential differential pressure can be shown by increasing increasing background background gas . NB 4 : Large cutting can be produced under conditions of very high underbalance from beneath the bit. NB 5 : Negative differential differential pressure during tripping may may result in swabbing swabbing , kick and and severely gas cut mud upon recirculation. recirculation. NB 6 : On stopping circulation ,differential pressure small or close to zero can cause connection gases to be produced from gas bearing permeable formations. formations. NB 7 : Connection gases produced from clays are indicative of reasonable high negative differential differential pressure. 9 - DRILLING EXPONENT : The rate at which a formation can be drilled is controlled by a number of drilling parameters which are : a- Bit size . b- WOB . c- Tooth Tooth shape shape and and distrib distribution ution and tooth tooth efficiency efficiency . d- Dril Drilli ling ng hydr hydrau auli lics cs . e- Diff Differ eren enti tial al pres pressu sure re . f- Matr Matrix ix stre streng ngth th . g- Form Format atio ion n com compa pact ctio ion n. h- RPM . Since DXC is a function of those drilling parameters . So by mean of plotting a normal trend for DXC of the area. So any deviation from that trend is an indication for abnormal formation. DXC = { Log(R/60N) / Log(12W/1000B) } . Corrected DXC = DXC *[ N. FBG/ECD] R = rate rate of penetration penetration (ft/hr) N = rotary speed speed (RPM) B = hole diameter N. FBG =normal =normal formation formation balance gradient gradient (PPG) ECD = effective circulating density (PPG) W = weight on bit (1,000 lbs.)
For metric system : DXC ={Log(R/18.29N) / Log (W/14.88B)} * (N. FBG / ECD) R in m/hr B in cm N in RPM N. FBG and and ECD in g/cc g/cc W in tones (1,000 kg) 10- PALEO INFORMATION : Abnormally high pore pressured zones are frequently related to certain environmental conditions within a given geologic time period. This depositional depositional environment environment is marked marked by presence of certain certain fossils.
CAUSES OF A KICK : 1- In Insu suff ffic icie ient nt mud mud den densi sity ty . 2- Sw Swab ab and and sur surge ge pre press ssur ures es.. When the pipe is tripped from the hole it acts like a piston so swab occurs causing bottom hole pressure reduction. As the pipe moves upward, frictional forces between the pipe, mud and bore hole wall will cause a pressure reduction . The maximum effect of this pressure reduction on mud density will be immediately below the bit. The maximum over pull pressure reduction will occur at the bottom of the hole . NB : An open drillstring will allow some fluid to flow through the jets allowing some degree of pressure relief. But if the drillstring has a float or down hole BOP swabbing pressure will be at a maximum . As a rule of thumb , this pressure reduction can be at least the same as the annular pressure loss. Swab values will depend on pipe pulling speeds and and hole condition. A safe weight to trip can be determined from the annular pressure losses using : W trip < W- [annular pressure losses psi] / [0.0519*D] Pressure reduction due to swabbing can be serious when drilling geopressured intervals, as the dropping of the BHCP/ECD may cause the will to flow. Large changes in mud density or effective mud density should avoided as these changes cause unexpected in magnitude which may lead to severe hole problems. The following items act to increase swabbing effect : a- Th Thic ick k fil filte terr cak cake. e. b- Bit balling. c- If nozzles nozzles are are blocked blocked and and back back pressure pressure value value in the the drillst drillstring ring . d- The speed speed at whic which h pipe is is pulled pulled has a great great effect effect on swabb swabbing. ing. e- High gel gel and viscos viscosity ity (as (as both have have a large large effec effectt on swabbing swabbing)) NB : If swab does occurs pipe should be run back to bottom and circulation out invaded fluids or gases. Surge pressure when running into the hole (pipe or casing )may be sufficient to overcome the fracture pressure of weak formations , So the pipe run into the hole should be at a speed that produces a surge pressure, below the minimum fracture pressure. This is important to be taken into our consideration any where in the bore hole as pressures are transmitted to the bore hole even when the bit is inside the casing. 3- LOW DI DIFF FFERA ERANT NTIA IAL L PRES PRESSUR SURE E: The majority of kicks occur when the bit is off bottom while tripping. When the pumps are shut down prior to tripping. There a pressure reduction reduction in the bore hole hole equals to the annuals annuals pressure loss(annular loss(annular friction friction pressure loss) loss) . If the pore pressure is nearly equals the mud hydrostatic pressure or even higher , flow may occurs when circulating stops and may lead to a kick . 4- DROP IN IN LENGTH LENGTH OF DRI DRILLI LLING NG FLUID FLUID COLUM COLUMN N IN BORE BORE HOLE HOLE : In case of loss circulation with presence of failure to keep the hole full, the fluid level in the hole will drop and thus result in loss in hydrostatic pressure due to decrease in length of drilling fluid column. If not controlled this hydrostatic pressure loss , this may lead to disturbance balancing formation pressure, pressure, and thus allowing influx of formation fluids into bore hole. 5- RI RISE SER R EF EFF FEC ECT T: The mud density used must be capable of balance the formation pressure. when the marine riser is removed. It is important to determine pressure reduction resulting from removal of riser on running casing job : EG : Water depth = 250 ft Air gap = 45 ft to RKB RKB to flow line = 5 ft Set 30” casing @ 600 ft
Total depth = 1500 ft M.wt = 9.2 PPG NB : Gas shows shows were recorded recorded at 800 ft and and 1100 ft. Calculate the hydrostatic pressure ! at 600 ft =9.5*(600-5)*0.0519 =293 psi at 800 ft = 9.5*(800-5)*0.0519=392 psi at1100ft =9.5*(1100-5)*0.0519=540 psi at 1500ft=9.5*(1500-5)*0.0519=737 psi In order to pull the riser it is necessary to displace it with sea water of density 8.5 PPG. So the resulting pressure would be: at sea bed = (250+45-5)*8.5*0.0519 = 128 psi at 600 ft =[9.5*(600-290)*0.0519]+128 =[9.5*(600-290)*0.0519]+128 = 281 psi at 800 ft =[9.5*(800-290*0.0519 =[9.5*(800-290*0.0519]+128 ]+128 =379 psi at 1100ft =[9.5*(1100-290)*0.0519]+128=527psi =[9.5*(1100-290)*0.0519]+128=527psi at 1500ft =[9.5*(1500-290)*0.0519]+128=726psi =[9.5*(1500-290)*0.0519]+128=726psi From results a reduction in EQMD = at 600 ft = 9.1 PPG at 800 ft = 9.15PPG at1100ft = 9.25PPG at 1500ft =9.3 PPG If gas zones at 800 ft and 1100 ft are permeable and with that big difference between 9.5 PPG on having riser and 9.1 and 9.15 PPG on removing riser, we might have a gas flow to bore hole. On removing riser, the fluid level in riser falls to sea level causing further reduction pressure. So the hydrostatic pressure will be : at sea bed = 8.5*250*0.0510 =110 psi at600 ft =[9.5*(600-290)*0.0519]+110 =[9.5*(600-290)*0.0519]+110 = 263 psi at 800 ft =[9.5*(800-290)*0.0519]+110 =[9.5*(800-290)*0.0519]+110 = 361 psi at 1100ft =[9.5*(1100-290)*0.0519]+110=509psi =[9.5*(1100-290)*0.0519]+110=509psi at 1500ft =[9.5*(1500-290)*0.0519]+110=708psi =[9.5*(1500-290)*0.0519]+110=708psi So from results an other reduction in EQMD = at 600 ft =8.5 PPG at 800 ft =8.75PPG at1100 ft=9 PPG at 1500 ft=9.1PPG To keep a 9.5 PPG gradient at 1100 ft will be necessary to increase the mud density into hole before disconnecting riser, the new mud weight can be calculated as follows : New M.wt =[(D*W) –8.5*(Dw –8.5*(Dw –BOPl)] /[D-Dw-A+BOPl /[D-Dw-A+BOPl ] D =vertical depth of hole(ft) from flow line W =mud density in hole (PPG) Dw=water depth (ft) BOPl =height =height of BOP stack from sea bed to riser riser conductor (ft) = eg 35 ft A =distance from flow line to sea level (ft) 8.5 = density of sea water (PPG) So the new M.wt ={[(1100-5)*9.5]-8.5*(250-35)} ={[(1100-5)*9.5]-8.5*(250-35)} /(1100-5)-250-40+35 = 10.2 PPG. So the new Mwt must be = 10.2 PPG to keep a 9.5 PPG gradient @ 1100 ft.
KICK RECOGNITION : 123456-
Incr Increa ease se in flow flow rate rate.. Incr Increa ease se in in pit pit volu volume me.. Well Well flow flowing ing with with pumps pumps off. off. Increase Increase in chlorid chloridee content content of drilling drilling fluid fluid at flow line line (above (above 100k mg/l). mg/l). Gas cu cutting. Circulating pressure drop because of the the unbalance between the hydrostatic column in the the drill pipe pipe and annuals annuals after penetrating penetrating an abnormal zone, it may take less pump pressure to circulate the fluid. Flow rate and pit volume increase would normally be observed before a circulating pressure decrease. 7- Hole not taking proper quantity of fluid while while tripping pipe out due to formation formation fluid invasion invasion into bore bore hole.(swab). hole.(swab). 8- Drag Drag whil whilee tri tripp ppin ing g in in .
WELL CONTROL AND KILL PROCEDUR PROCEDURES ES 1- Record predetermined kill rate (SPM), and kill rate pressure[Other names :Slow Circulating Circulating Pressure](SCP) or Reduced Circulating Pressure (RCP) ] . A predetermined slow rate for circulation out a kick is recorded each tour. This is done to stand on any change in slow rate pressure due to chock line friction or kill line friction. also to compensate for changes in depth or any fluid weight changes. This slow rate is recommended to be ½ of the normal rate or even less to prevent any excessive well bore pressure, when circulating out a kick through chock lines or kill lines. 2- Position Position Kelly Kelly and and tool joint joint , so that that tool tool joint joint are clear clear of sealing sealing eleme elements nts . 3- Stop Stop pump pumpss and and chec check k for for flow flow.. 4- If flow flow is noted, noted, close will will in without without delay. delay. 5- Record Record shut-in shut-in drill drill pipe pressure pressure (SIDP (SIDP)) and shut-in shut-in casing casing pressure pressure (SICP) (SICP) . The drill pipe pressure gauge or pump pressure gauge is in reality a bottom hole pressure. After a well kick , and when the pump is off and the well is shut-in the drill pipe is then a large gauge stem that reaches to the bottom of the hole . So the drill pipe pressure gauge reads in a some how the bottom hole pressure as seen from the gauge stem. PS : If the drill pipe was empty the surface gauge would read bottom hole pressure. But the drill pipe is filled with the drilling fluid, which is normally not contaminated so the gauge reading shows the difference between bottom hole pressure and the hydrostatic pressure of mud column in the drill drill pipe. The SIDP (or kick pressure)is the difference between the hydrostatic pressure exerted by the mud column in the drill pipe and the bottom hole pressure pressure exerted by formation formation (formation (formation pressure). Formation pressure = stand pipe gauge reading after stopping the pump (SIDP) +the hydrostatic pressure of the drilling fluid column inside the drill pipe . NB : Casing pressure will normally always be higher than drill pipe pressure , because kick gas or water well normally be lighter than the mud and by turn cuts M.wt in annulus . This makes the mud column pressure in the annulus less than the full non contaminated column of the mud in the drill pipe. So the formation pressure acting against the hydrostatic pressure of mud column in annulus will be much easier than acting against against the hydrostatic hydrostatic mud column inside inside the drill pipe pipe and thus the annulus surface pressure pressure will be higher than the drill pipe pressure. Shut-in drill pipe pressure can be determined by : a- Read direct directly ly from from gauge if there there is is no back pressur pressuree value in in the string string . b- If a back pressure pressure value in the string string then : Start pump slowly , continue until fluid moves or pump pressure increase suddenly . Watch casing pressure , stop pump when the annular pressure starts to increase. Read drill pipe pressure at this point. If casing pressure increase above its original pressure when closing the well this would indicate trapped pump pressure must be subtracted from drill pipe pressure reading at the point when stopping circulation. This is the SIDP . These procedures should be repeated until having the same value two consecutive times . OR : If predetermined slow rate and slow rate pressure have been recorded. Open chock and start pump slowly . Hold casing pressure at the same level as the SICP . Bring pump speed up to predetermined slow rate , keeping casing pressure constant. Read new circulating pressure at predetermined slow rate from stand pipe gauge (at this kick situation) . Then subtract predetermined circulation pressure at predetermined predetermined slow rate from the new circulating pressure in this kick situation at the same predetermined slow rate. The difference will be the amount of underbalance or SIDP . 6- Check Check BOPs BOPs and mani manifol fold d for any leak leakss . 7- Check Check accumu accumulat lator or pressu pressure re.. 8- Check Check flow flow line line and and check check exhaus exhaustt lines lines for for flow flow . 9- Record Record volume volume gain gain and and mark mark pits. pits. 10- Fill Fill up kill kill shee sheett . 11- Calculate Calculate well well kill calculat calculations ions . a- Initial circulating pressure = slow circulation circulation pressure pressure + SIDP . As previously mentioned a predetermined slow circulation rate (usually ½ the normal drilling rate)and corresponding pressure loss versus depth and variation in M.wt should recorded each tour . This recorded pressure plus the SIDP will equal the initial circulating pressure (ICP) (ICP) . If no predetermined slow rate has been recorded the SICP can be used as a reference point .
Open the chock slightly and bring the pump up to a slow rate while maintaining the original SICP at all times . When a satisfactory slow rate has been reached and the casing gauge still reads original pressure , the initial circulating pressure can be read from the drill pipe gauge . b- Calculate required required M.wt increase increase =SIDP =SIDP / (0.0519*depth) EG : M.wt =12 PPG SIDP =260 psi TVD =10,000 ft M.wt increase =260 /(0.0519*10,000) = 0.5 PPG c- Calculate Calculate requir required ed M.wt M.wt (kill M.wt) M.wt) to to equalize equalize format formation ion pressure pressure = required M.wt increase + original M.wt So the new M.wt to equalize formation pressure =12 + 0.5 = 12.5 PPG. d- Final Final circ circula ulatio tion n pressu pressure re (FCP) (FCP) : With the new M.wt at slow circulating rate = ICP-SIDP*(Mwt 2 / Mwt1) =SCP*(new M.wt / old M.wt) e- Maximu Maximum m allow allowabl ablee casin casing g press pressure ure : So as at any time not to reach that value . I.E : Always keeping casing pressure under maximum allowable casing pressure with a satisfactory value . Otherwise causing changing to the casing if its pressure increases . = (Fracture M.wt – Present M.wt) * Casing depth * 0.0519 .
TYPES OF MUD KCL POLYMER MUD Composition and properties : Kcl-polymer mud are considered to be the most inhibitive mud against clay , fluid interaction on drilling massive layers of hydratable clays and shales. Its beneficial effect is based on inhibitive properties of potassium ions towards shale hydration and on the encapsulating and coating of both cuttings and and bore hole wall by selected polymers polymers . Kcl-polymer mud is often refereed to as (low solids) mud which means that : No collided or suspended suspended solids are are used in the initial initial make up. Treatment is geared to prevent the dispersion of drilled solids to enable solids removal (no thinner added) . 1- Fresh H2O, saline H2O, brine H2O or even sea water , in all types of water should check and treat the hardness of used water as polymers used are are very sensitive to Ca content . so always keep Ca Ca content below 400 mg/l . 2- Kcl ,(however ,(however the concentration concentration of Kcl may vary depending on the degree degree of inhibition inhibition required) required) the typical concentration concentration is 10% by W or 35 lb./bbl lb./bbl . Alternatively Alternatively concentration Kcl brine may be diluted in a 1: 1 ratio with water. 3- Caustic Caustic soda (0.5 lb./bbl) lb./bbl) to maintai maintain n pH between between 9-10 to provide non corros corrosive ive conditions conditions.. 3 4- Soda Soda ash ash (0.1 (0.1 lb./bb lb./bbll or or 0.3 0.3 kg/m kg/m ) to treat out Ca content to be less than 400mg/l. 5- PAC-LV Resinex & starch {3lb./bbl {3lb./bbl or 8.6 hg/m3hg/m3- 4lb./bbl or 11.5kg/m3} 11.5kg/m3} for fluid loss loss control. 3 6- PACPAC-HV HV {1-2 {1-2 lb./b lb./bbl bl or 2.8-5 2.8-5.7 .7 kg/m kg/m } or XCD polymer(BipolyE) (0.5-1.0 lb./bbl or1.5-2.8 kg/m 3). PACs are CMC- type polymers. They are different from technical technical grade CMC in that the molecules have more anionic sites (promoting (promoting adsorption into clay particles) are larger(higher viscosity) and the material contains less impurities. 7- Polya Polyacry crylom lomide ide (1 (1 lb./bb lb./bbll or 2.8 2.8 kg/m kg/m3) (optional)is added to encapsulate clay cuttings. This additive as a liquid concentrate (as a dispersion in oil) to facilitate rapid addition to the mud. 8- Bari Barite tess as as req requi uire red. d... PARAMETERS NEEDED : 1- Dens Densit ity y > 10.8 10.80 0 kg/ kg/m3 m3 . 2- M.F M.F vis visco cosi sity ty 45-5 45-50 0 sec sec . 3- PV 15-20 15-20 cp. (14-20 (14-20 m Pa. Pa.sec sec). ). 2 4- YP 2020-25 25 lbs/ lbs/ft ft (10 12 Pa) . 5- pH 9. 9.5-10.5 . 6- API API flu fluid id loss loss < 10 10 cm cm3 . + 7- K content 52 gm/l . NB : If its required a low fluid fluid loss mud directly directly from the start start (e.g. : permeable permeable formations closely closely below the casing show) show) addition of fine particulate matter could be required to aid in filter cake build up , use of prehydrated bentonite (approximately 5lb./bbl or 14 kg/m3) or finally graded Calcium carbonate with a medium particle size of 25 micron , is then recommended . Effect of Clays and Shales : The polymer (Polyacrylomide) (Polyacrylomide) in Kcl-polymer mud is through to aid in shale stabilization. It is generally perceived that the polymer (anionic polyelectrolyte) polyelectrolyte) is adsorbed at the positive sites on the edges of clay crystal lattices. It seems likely that this adsorption occurs multiple points along the chain of the elongated polymer molecules , thus linking particles together and form a jelly coating at the surface of the drilled shale and clay particles and on the pore hole wall and thus slow down the rate of transport of water into the shale. It was found that not all anionic polymers seem to be equally effective encapsultors only Polyacrylomide and biopolymers (XCD polymer) have encapsulating encapsulating properties properties . Inspite of its inhibiting properties , mud shale interaction can not be prevented completely as a result of ion – exchange with drilled clays the K + content of the mud will decrease . And as in bentonite and gypsum based muds the mud properties which are affected by shales are: a- Viscosity . b- Density . c- Plas Plaste teri ring ng prop proper erti ties es . d- pH . e- Water loss . # The increase of water loss is due to : It is well known that the fluid loss in this type of mud is controlled mainly by polymers. So as a result of depletion of these polymers which adsorb onto drilled shale particles , together with entrance of clay properties into mud in a flocculated state, poor filtration characteristics characteristics .
I.e. increased value fluid loss will result in a thicker mud cake. # Still many operational problems related to mud shale interaction are reduced by using Kcl polymer muds . EG : Balling problems will be less than during drilling with other mud types . If still occurs ,this an indication for insufficient inhibition and should be treated by increasing Kcl level . A- Tight Hole and Over pulls pulls : They are often experienced when drilling gumbo shales, because shale hydration is reduced , hole erosion is reduced as will as a result the well bore will be in gauge , which is easily experienced as a tight hole . In a dispersed system rapid erosion would avoid this. This can be avoided by continuos reaming before each connection . B- Caving Caving and and Hole Hole Enla Enlarge rgemen mentt : In more brittle shales, sloughing resulting in Caving and hole enlargement is often a result of hydration along micro fractures, permeable bedding planes and other lithological lithological inhomogenities. The degree of further disintegration disintegration of cuttings depends on the shale strength and hydration potential and may therefore be limited in a Kcl polymer mud . Caving circulated out of the hole are often hard and dry with a surface which is clearly not affected by hydration . Operational problems in sloughing shales are Over pulls and difficulties in hole cleaning. When using less inhibitive muds dispersion of Caving may be the reason that sloughing remains unnoticed during drilling , because Caving circulated out cuttings size. An excessive hole size over the unstable zone is often the only indication of shale sloughing in these muds .To avoid these problems its necessary to adopt certain operational problems such as frequent check tripping to restore the hole gauge and to thoroughly clean the hole prior to making trips and ream and clean prior to making drill pipe connection . # Treatment Whilst Drilling Shales and Clays : In Kcl polymer polymer muds muds inclus inclusion ion of clay clay and shale shale is avoide avoided d by , hydrat hydration ion is minimi minimized zed and partic particles les are protecte protected d from from disintegration disintegration by encapsulation . Kcl polymer muds are also called Low Solids Muds . # Viscosity and Fluid Loss Control : They are avoided by polymers (XCD polymer, PAC-HV for viscosity and modified starch or PAC-LV for fluid loss control) . Bentonite should not be used for this purpose as it contributes to the clay content of the mud . Chemical treatment with thinner to control rheology should not be done , because clay particles would then be dispersed to unremovable size # Both Viscosity and Density : should be controlled by dilution dilution only, this normally implies disposal of old mud and addition of fresh mud. Treatment indicators are the(rheological indicators PV, YP, Gels) which may exceed set limits, and MBT. NB : The upper limit of bentonite association is 25lb./bbl or 72kg/m 3 . Above this value the rheology will rapidly increase to intolerable values . NB : Always the added new mud should should be at least ¼ of the circulating volume and and should contain all additives as as required in the basic make up. NB : One could be tempted to add fresh volume with a reduced viscosity to counteract the high viscosity in the circulating mud. By doing so , one would start to convert to a system which relies on the viscosity being being provided by drilled clays rather than by polymers . Reduction of the overall polymer level result in incomplete encapsulation hence increased hydration and dispersion of clay particles and a more rapid deterioration of mud properties. # K + and Polymer may deplete rapidly while drilling reactive clays and shales and the level of these additives should mounted closely to enable timely replenishment . The Cl - level of the mud remains virtually constant , however it therefore not possible to monitor K + content in Kcl –muds by relating to Cl - measurements. Both Kcl and Polyacrylomide (which is available as a liquid concentrate) can be added directly directly into the active active system (no hopper hopper required). Its good practices to start off with a slightly higher Kcl level than specified. EG:(40lb./bbl or 115kg/m 3) when 35lb./bbl or 100 kg/m 3 is specified. A more or less constant addition rate can be estimated from the observed rate of depletion. In area when mud plant facilities are available Kcl is often supplied as concentrated brine (80-90 lb./bbl Kcl). Altranativly Kcl supplied in big bags (1or1.5MT content). # For Polyacrylom Polyacrylomide ide additions additions in reactive shale a rule of thumb is 1 pail (approximat (approximately ely 25L polymer polymer solution) for every single single drilled. Addition rate should be adjusted to maintain the excess polymer content at approximately 0.5 lb./bbl or 1.4 kg/m 3 in the mud at the flow line. Addition of PPA can result in a thickening of mud in the active pit (say to a MF viscosity of 60-70 sec). This is perfectly accepted as it should be realized that the concentration is automatically automatically reduced when the mud enters the annulus where where the polymer is adsorbed onto the surface of cuttings and formation face . The Polyacrylomide content may not depleted because restoring the level may cause excessive viscosity . Deficiency of polymer may result in the build up of fine hydrated clay particles in the mud . Subsequent addition of polymer may then result in blocky structure of flocculated particles with accompanied effect on the mud viscosity, which can only be restored by prolong shearing and circulating .Physically this phenomenon is very similar to the (over the hump)effect in bentonite muds upon salt or Ca ++ additions .
FACTS [% of K +] • 3% (W) or less is enough to consolidate illitic shales. • 20% (W) is required for gumbo shales of young age. • 10%(W) 35 lb./bbl is desired to whenever the requirements dictated by formation properties are not known .
1.
2. 3. 4. -
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INDICATORS FOR INCOMPLETE INHIBITION : When cuttings generated are sticky sticky I.E cuttings generated generated should be firm and move move off the shaker screens screens as discrete particles and when squeezed in the hand they should not form a sticky mass . If sticky means that hydration is still taking place and inhibition is incomplete. High reduction rate of K + ion level . Rapidly Rapidly deterior deterioratin ating g rheology rheology propertie propertiess (requiring (requiring high high dilution dilution rate) rate) Occurrenc Occurrencee of potent potential ial proble problems ms (balling (balling , tight tight hole). hole). Increasing the Kcl level improves the inhibiting effect of the mud. Increasing the polymer level does not contribute to better inhibition . As long as some excess polymer can be detected in the mud from the hole encapsulating is considered optional. Polya Polyacry crylom lomide ide can be left left out witho without ut adver adverse se effect effect on the mud or the drilling drilling performa performance nce . This This indica indicates tes that that the encapsulating effect of other polymers present in the mud( EG :XC polymer ) can be sufficient. It is recommended however to include Polyacrylomide if such experience does not exist . Kcl polymer are sensitive to drilled solids which might get into the mud and thus will affect viscosity and gels of the mud, therefore it is required high efficiency solid removal equipments especially with respect to shale shaker.
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EFFECTS ON DRILLING ANHYDRITE : Contamination by anhydrite does not affect the properties of a Kcl polymer mud. The only indication of anhydrite contamination will be an increase of dissolved calcium to approximately 600 mg/l which is not sufficiently high to give a noticeable effect on Polyacrylomide Polyacrylomide . NB : Hydration Hydration of drilled clay is sufficiently sufficiently prevented by K + to avoid flocculation by Ca +2. -
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EFFECTS ON DRILLING CEMENT : Since drilled clays have been converted to a form with K + as the base ion , which provides inhibition against hydration . So the cement will only show an increase of pH and Ca +2 content and mud alkalinity (P m, Mf ) . In case of mud containing containing polyacrylamide polyacrylamide Ca+2 levels in excess of 1000 mg/l will deactivate, precipitate and consume the polyacrylamide. But still other polymers ( PACS, PACS, XCD POLYMER POLYMER AND STARCH STARCH ) will will have a higher higher tolerance to Ca+2. Ca+2. Ca+2 levels in excess of 2000 mg/l and high pH in excess of 11.5 will affect, precipitate and break down XCD POLYMER, PACS and MODIFIED STARCH. TREATMENT WHILE DRILLING CEMENT: -
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With NAHCO3 ( 0.25 – 0.5 lbs/bbl OR 0.7 – 1.4 kgs/m3 ) In case of severe contamination with cement, dump the contaminated mud.
EFFECT ON DRILLING SALT
The properties of KCL – POLYMER Mud are not affected by salt contamination other than increase in cl- content. Similar to other non – saturated mud, the mud should be saturated prior drilling through a salt layer.
The effect and treatment of Kcl – poly mer mud when drilling different formations M.wt
Vis
WL
MBT
pH
Alk
Clay + Shale
+
++
+
++
-
-
Sand + Silt
+
+
+
+
++
++
Formation
CL
Ca
K
Treatment
--
Add K – CL & polymer, dumb old partly, replace by fresh mud @ MBT 25 bbl, solid removal. Solid removal, dumb and replace by fresh mud.
pol
Pretreated with NaHCO3, restore fluid loss and polymer content, dumb contaminated contaminated mud. No treatment required .
Chalky L. ST. Cement
+
++
Anhydrite
+
Salt H2S / CO2
Formation Brine
++
-
--
--
--
--
++
Consider conversion to salt saturated mud.
++
Add C. soda & suitable scavenger Zn CO3 (H2S) Lime (CO2). Increase M.wt, treat Ca w/ soda ash, pH w/ C. soda Correct fluid loss, restore polymer, and consider conversion to salt saturated mud.
++
--
GEL – POLYMER MUD Preparation : 1. Water . 2. Caustic so soda . 3. Soda Soda ash ash to to tre treat at out out Ca Ca +2 . 4. Bent Benton onit itee 5-1 5-10 0 lb. lb./b /bbl bl . 5. Polymer (viscosifires type depends on depth, temperature, pressure and and salinity ), (CMC – HV, XCD, PAC – R, CATA Free, BIPOLY E ) 3 lb./bbl . 6. Starc Starch h – poram poramile ile in in case case of high high salini salinity ty . 7. W.L. reducer (CMC (CMC – LV, LV, Resinex[used when when MBT>5lb./bbl, MBT>5lb./bbl, but never use in high salinity salinity ], SALTEX, SALTEX, POLYPOLY- PAC, PACPAC- SL, SL, POLY TRIX ) . NB : Mixing viscosifires and W.L reducers must be very slow , together with good agitation , and use guns while mixing (at least 10 min/sack). As fast addition will result in poor mixing which by turn will result in : a. plugging plugging of rig rig pump pump screens, screens, and thus pump pressure pressure increase increases. s. b. Fish eye . c. The The used used pol polym ymer er wil willl be inac inacti tive ve . NB : On using using mud from previous previous phase first first of all work on Ca+2 contaminations resulting from cement by NaHCO 3 to adjust pH , viscosity, Pf , Mf , Pm and dump highly contaminated mud . Parameters Needed : Parameters 1. pH 10-10.5 . 2. Visc iscosi osity 45 s . 3. YP 15 15 –20 4. PV +/ +/- 5 . 5. MBT 5 – 10 . 6. W.L W.L as as re requir quireed . 7. Dens Densit ity y as as req requi uire red d. Effects of Different drilled Formations : 1. Dr Dril illi ling ng cl clay ay or sh shal ales es : a. Increase MBT . b. Cause flocculation flocculation followed by aggregation . Thus increase viscosity viscosity at beginning then then viscosity will will decrease . c. Incr ncrease we weight . Treatment : a. Dump Dump and and dil dilut utio ion n with with fre fresh sh wat water er . b. Add water loss reducer . c. Solid removal . d. Add Add dis dispe pers rsan ants ts if if nec neces essa sary ry . 2. Dr Dril illi ling ng sa sand nd + sil siltt : a. a. Incr ncrease ease weig eight . b. Increase viscosity viscosity + PV . c. Increase W.L . Treatment : a. Remove Remove soli solids ds by solid solid contr control ol equip equipmen ments ts . b. Dilute by mean mean of fresh mud . c. Add W.L W.L.. reduce reducerr and disp disper ersan sants ts if nece necessa ssary ry . 3. Dr Dril illi ling ng Ce Ceme ment nt : a. Increase hardness . b. Increase alkalinity pH, Pf , Mf , Pm . c. Increase W.L W.L . d. Incre ncreas asee vis visco cosi sity ty . e. Decrease YP . Treatments : a. Treat with NaHCO 3 in case of high pH , soda ash Na 2CO3 in case of low pH . b. Add W.L. reducer (RESINEX, POLYTRIX, and OR CMC- LV) . c. Add thin hinner ner (S (SPERSE RSENE) . d. Add Add visc viscos osif ifie ierr to ret retai ain n YP if nec neces essa sary ry e. Dump Dump high highly ly cont contami aminat nated ed mud mud and and add add fresh fresh wate waterr .
4. Drilling Anhydrite a. Increase Ca+2 content . b. Increase viscosity . c. Increase W.L. Treatment : a. Add soda ash . b. Thinner . c. W.L. reducer . d. Cons Consid ider er conv conver ersi sion on to gyps gypsum um mud mud . 5. Dril illlin ing g Sal altts a. Decrease pH . b. Increase then decreases viscosity . c. Increase weight . d. Increase W.L. e. Foam Foamin ing g due due to chl chlor orid idee inc incre reas asee . Treatment : a. Add thinner . b. Dilution and dump dump sand trap every every 4 connections . c. Correct W.L. d. Add defoam defoamer er [no foam, foam, or or AL Stear Stearate( ate(1kg/g 1kg/gallon allon diese diesell to be spray sprayed ed on surface surface of of foamed foamed mud in in pits)] pits)] . e. Use sol solid contr ontrol ol equip quipm ments ents . f. Cons Consid ider er conv conver erti ting ng to salt salt satu satura rate ted d mud mud . 6. Effects of of CO2 Causes CO3 gelatin. a. decrease pH . b. decrease alkalinity alkalinity of mud . c. inc increase ease visc iscosi osity . d. increase W W..L. Treatment : a. If pH is is not not too too low low add add cau caust stic ic sod sodaa . b. If pH is too low add lime . c. If pH pH ok add add thinn thinner er (Li (Ligno gnosul sulfon fonate ate + caus caustic tic soda) soda) .
GENERAL TROUBLE SHOOTING IN WBM: 1.
In case of increase of % of gas gas in system , which will affect affect the mud mud weight even with true true balance increase surface surface area of mud ? Putting on Desander to increase of gas from the mud . 2. In case case that that in acti active ve is cont contami aminat nated ed with with CO2 which will lead to CO 3 gelation . This will result in foams . Add lime straight away on system to get rid of CO 3 and by turn foams (CO2 gas) 3. NaHCO3 + cement =(may result in in ) come CO2 dissolved in mud , this only take place at low pH . 4. For For qui quick ck trea treatm tmen entt of of Ca Ca+2 contamination add NaHCO3 directly on settling + intermediate . I.E mud out . 5. In case case of a gas gas kick while while circulat circulation ion through through check check use use pH paper paper after after hydrated hydrated with with H2O. Put it in chock line ,if CO 2 is present the color will change from yellow to green which indicate acidic medium . 6. In case case of bit bit bal balli ling ng a. Batch (H2O + caustic soda + Spercene ) . b. Drum drilling detergent . c. Redicoat . d. Nut plug plug to make make frict friction ion surfac surfacee under under bit bit . NB :The higher higher the salinity salinity the lower the the pH . The higher higher the Ca+2 contamination . NB : Ca+2 can be treated by caustic soda , the ppt is Ca(OH) 2 (lime) . NB : Treating Treating Ca+2 by mean of caustic caustic soda . So required required cut of X 0.1/100 = ppb of NaOH to treat out Ca+2
OIL BASE MUD Introduction : The most important feature of any drilling fluid is that there no interaction between the fluid and the drilled formation which if present will affect the mechanical properties of the formation . If a water based system is used the water will inter the formation causing change in its mechanical properties and thus cause instability of this formation(this can be minimized by using a system like Kcl-polymer mud). However the only way to prevent the water wetting of the pores of the rock is to contact the formation with a fluid thus will not wet the rocks and thus will not enter the pores and cause a change in the mechanical properties of the rocks. These fluids having oil to be the continuos phase of the drilling fluid .
ADVANTAGES
Shale stability and inhibition. Temperature stability. Lubricity Resistance to chemical contamination Gauge hole in evaporite formations. Solids tolerance. Reduced production damage. Reduced tendency for differential sticking. Drilling under-balanced. Re-use. Reduced cement cost High penetration rate. Flexibility. Reduced of stress fatigue. Reduced corrosion.
DISADVANTAGES
High initial cost per barrel. Mechanical shear required. Reduced kick detection ability. Pollution control required. High cost of lost circulation. Disposal problems. Solids control equipments based on centrifugation does not work effectively. Hole cleaning. Rig cleanliness. Special skin care for personnel may be required. Hazards vapor. Effect on rubber. Fire hazard. Special logging tools required. Gas stripping.
Oil Based Drilling Fluids are of Two Types : 1. Oil Base ase Flu Fluiid : This type does not rely on entrained emulsified to drive the basic properties of rheology and fluid loss control. Normally these these would be formulated formulated without water. water. Generally Generally contain less than than 10% water( water( usually from 1%-5%by 1%-5%by volume of water). water). This formulated with refined oils such as diesel fuel. NB : Crude oils can be used (they contain high high levels of air blown asphalts). asphalts). 2. Inve Invert rt Emul Emulsi sion on Flui Fluid d: Has a continuos exterior oil phase but must have water into interior phase to provide same of the rheological properties and fluid loss control. This type may contain from 10% - 50% water by volume with the continuos oil phase which can be oil or diesel . OBM is mainly composed composed of : 1. The oil phase (mainly diesel) Which is the continuos phase into which every thing is mixed ? 2. The brine phase (Ca Cl2 + H2O) It exists in the drilling fluid in the form of extremely small droplets ranging in size form submicron to a few microns in diameter. These droplets act as solids in the fluid and impact the basic viscosity . Usually Ca Cl 2 not Na Cl is used as it gives greater flexibility in adjusting the activity of the s ystem . 3. The The soli solid d phas phasee (bar (barit ite) e) : This consists mainly of the weighting agent., which is mainly barite . But also having fine drilled solids which must be minimized by removal as much as possible. possible. This done by adding lime. The main advantages and reasons for using OBM : 1. Protec Protectio tion n of of prod produci ucing ng sands sands : As some producing formations have clays in their pore spaces that swell when contact with water base mud due to water mud filtration . This swelling results in partial to complete blockage of the formation which by turn prevents the passage of formation fluids. The oil filtration of an oil muds does not swell formation clays and therefore does not reduce permeability. Even on drilling clean sands with water base mud may cause water blocked because of the interfacial and surface tension properties of water mud filtrate. 2. Drilli Drilling ng wate waterr sensi sensitiv tivee shal shales es : Some shale formations that slough when contacted with water mud are drilled readily with oil mud. The external phase of the oil mud is oil and does not allow water contact the formation, the shales thereby prevented from becoming water wet and dispersing into the mud or caving into the hole. The result is closer to gauge hole, this have a great advantage on drilling deep wells or deviated wells and thus prevent and relieving stuck pipe . 3. Dril Drilli ling ng deep deep hot hot hol holes es : Oil mud do not undergo any chemical changes at high temperature, which cause solidification solidification of water muds, and thus this advantage make oil muds an excellent drilling for deep hot wells. 4. Drilli Drilling ng solubl solublee form formati ations ons : The drilling of water soluble formations such as salt, potash and gypsum by using water base muds can present a difficulty in controlling viscosity, gel strength, yield, filtration and density. Also the problem cavities in massive salt formations. Oil muds aids in overcoming these problems as the external of an oil base mud is oil and non of the normally encountered salts are soluble in the mud. NB : Two Two exceptions are calcium calcium chloride and magnesium chloride chloride which will will dissolve in the the emulsified water water , but have have no adverse effect on oil mud properties . NB : The non polar nature nature of the oil muds ensures that that the system is is in generally insensitive insensitive to the the chemical contamination contamination that affect affect water base systems, such as contamination with salt, anhydrite, cement, carbon hydroxide, sulfides . 5. Coring Coring fluid fluid for for oil oil prod produci ucing ng zones zones : When water muds a coring fluids , invasion or flushing may destroy the reliability of the data obtained from the core . The total amount of core which is recoverable may be reduces when water mud is used . For these reasons oil muds is used as a coring fluid.
As oil muds have a low oil filtrate which allows cores to be cut with only slight invasion and flushing. NB : The water in the oil oil mud which is is squeezed into the core by the high pressure pressure under core core bit will slow slow upon distillation distillation of the core, as connate water. For this reason its desirable to prepare either oil fluid have a very low percentage of water or water free system to avoid any damage to the core , but this is quite expensive . 6. Spotti Spotting ng to fre freee differ different ential ially ly stuck stuck pipe pipe : Because of lubricity property of oil and oil muds, it have been used to prevent and relieving all types of stuck pipe. # Two things are always present when differential sticking occurs : • A permeable zone exposed in the open hole. • A mud with sufficient solids, and a sufficient high filtration rate under down hole conditions, to deposit a thick filter cake. Therefore to relive differential sticking , it is necessary to effect some change in the cake already deposited . And to prevent differential differential sticking it is necessary to prevent deposition of a thick filter cake. Because of the ability of an oil mud to penetrate the water mud cake and because the inherent lubricity of oil muds they are quite successful in freeing pipe that was differentially stick while using water mud. It is well known that oil muds have low filtration rate and head thin cakes at elevated temperature and pressure . 7. Plasti Plasticc flow flowing ing shales shales : Gumbo shale is unique in that it contains low concentrations of hydratable clay(10% - 25%) and a large amount of relatively fresh water (20% - 30%) . When water base mud is used to drill this(gumbo) the shale immediately disperses into the mud. The mud becomes so thick that drilling must proceeds at controlled rate or the mud will plug the annulus. Bit and collar balling , stuck pipe , also shaker screens become plugged because because of cutting are are soft and gummy. gummy. Oil muds overcome all gumbo drilling problems but only solid control problems . NB : By incorporating incorporating a fairly fairly highly concentration concentration (10-15 lb../bbl) lb../bbl) of Ca Cl Cl 2 into the water phase of an oil mud a dehydration of this wet shale would occur and make it drill and act like firmer shale type . The mechanism of this dehydration appears to be osmotic because of the difference difference in salt concentration in the shale and in the water phase phase of the oil mud. 8. Casing Casing pack pack and and packe packerr fluid fluidss : It was found that oil muds have a long term stability and non conduct nature which make them useful in casing packs and packer fluids in completion and workover situations . The requirements for a fluid that is to be placed in the casing tubing annulus are relatively simple. This fluid should be : a- Provide density density required to assist in maintaining maintaining the packer packer seal and and prevent burst burst or collapse collapse of pipe. There should be no compacted settling of solids and slugging and top oil separation should be minimized . b- To be non – corrosive corrosive . c- To be fluid fluid enough to permit permit placem placement ent a small small annulus, annulus, or a good clean clean displacem displacement ent in a large large annulus annulus . d- To be stabl stablee in down down hole condit conditions ions of of temperat temperature ure and and pressure pressure . e- Have a very very low filtrati filtration on rate to avoid avoid signific significant ant loss of volume volume or change change in composit composition. ion. f- Be suffici sufficient ent gelled gelled to to prevent prevent migrat migration ion of fluid fluidss into the the annulus annulus . g- Protecte Protected d casing casing from from corros corrosion ion by formatio formation n fluids fluids . It is not difficult to prepare an oil mud to meet these requirements . But if the fluid to be used in an open hole annulus , so to migrate corrosion attack , or to facilitate recovery of the casing later, it must be meet much higher standards . 9. To obtain obtain proper proper pressure pressure control control via formatio formation n pore pore pressure pressure : 10. Can be stored stored and reuse reused d: Thus having the advantage to reduce cost comparing with water base mud which can be only used in one well. 11. Low Low solids solids oil muds muds : a- Diesel oil 85% as fast fast as water water base mud and the same same factors that that reduce drilling rate rate whether oil oil or water water is the the base fluid. fluid. b- Diesel oil is less dense than than water . c- Solids Solids do not dispe disperse rse in in oil oil readily readily as in in water water . d- Diesel Diesel oil oil is rela relativ tively ely non non – corro corrosiv sivee . 12. Treated curds : In some areas low cost oil muds are prepared for drill – in and completion work, simply by treating a field crud to give some property such as filtration control control or carrying carrying capacity.
1.
Requirements for preparing OBM : E MUL / E CON : These two products combines to form a very tight film of surfactants at the interface between brine droplets and oil phase , and thus ensures the emulsion stability in the presence of high temperature and high pressure. These two products are high molecular weight sodium and calcium shapes, having a slow acting and requires high shear for dispersion to obtain highly stable water in oil emulsion. NB : Since no fatty soaps are are employed , so there is no instability instability introduced introduced at low alakalinities alakalinities introduced introduced by H 2S and the system will not react adversely with high levels of magnesium contamination contamination . Also E MUL acts as an effective oil wetting agent, this helps to make the fluid resistant to contamination from drilled solids and salt.
E CON also imparts the basic filtration control properties to the drilling fluid, upon addition of this product it requires the presence of lime but after the initial reaction reaction the presence of lime is no longer longer required . 2. Lime : • Gives alkalinity to mud. • React with H 2S gas H2S + Ca(OH) 2 → ↓ CaS +H2O . • 3.
Help to give gel mud stability (leak of lime will cause high viscosity, high YP, high PV). E VIS : It is an organophilic clay which is a viscosity agent which gives the drilling fluid excellent rheological properties (viscosity and carrying capacity) this product also aid in filtration control. 4. E TON : Is an asphaltic HT HP filtration reducer . It also functions as a thinner and difflocculant for high density fluids in high temperature environment. 5. E WET : This product is an extremely powerful oil wetting agent developed to give the drilling fluid extra stability when drilling extremely wet formations . It also acts as a thinner when substantial quantities of solids are present . NB : While adding barite add add E WET slowly slowly at the pit to wet barite and and keep it always always in suspension and prevent its settling settling . I.E So as solids get gate by diesel. Mixing OBM : Diesel + Emulsifier (MUL or CON) +
⇐
H2O + Ca Cl2
Lime 1. Fill Fill tank tank with with requ require ired d volume volume of diese diesell . 2. Add emuls emulsifi ifier er (15 (15 lb.,/b lb.,/bbl) bl) and and mix mix thoroug thoroughly hly . 3. Dissolve Dissolve requir required ed salt salt in a separate separate tank in the required required H2O. Add brine slowly under maximum shear to the diesel E MUL mixture . 4. Simul Simultan taneou eously sly add add the the Lime Lime and and the the E CON CON . The mud color will darken with shear and time . Shear for maximum stability . 5. Add require required d E VIS (5lb./ (5lb./bbl) bbl) and and shear until until require required d rheology rheology is achieve achieved d. 6. Add require required d E TON (8lb./ (8lb./bbl) bbl) and and shear until until requir required ed rheology rheology is achieve achieved d. 7. Add all Barit Baritee if high densitie densitiess are required required a small small dose of E WET (1-2 (1-2 lb./bbl) lb./bbl)is is recommend recommended ed . 8. Agitate Agitate and shear shear the the system system as large large as possibl possiblee to get the the maximum maximum stabili stability ty . Precautions : A. Make on water water additi addition on while while adding adding Barite, Barite, or vice vice versa. versa. I.E : Barite addition should never be made in the presence of free H 2O . B. Vigorous agitation agitation while adding (high shear)is necessary necessary when adding adding materials materials to give give stability to the mud . C. Do not increase increase mud weight when when the when the mud mud has a higher percent percent water then then that desired at at the final weight. weight. D. When oil is added added , E MUL + E VIS + E TON + E WET, should be added so that the the overall concentration of these materials in the mud is not reduced . E. Determine the oil/water oil/water ratio ratio and add proportionate proportionate amounts of oil and water. water. For example if if O/W ratio is 75/25, then add add the volumes of diesel oil and volume of water per time period(hour) . F. The amount of each oil mud product to be added added in maintaining maintaining the mud mud is based on the total total volume of new mud mud prepared . The suspension additives can usually be omitted from new volume unless large volumes are prepared, or weight materials is settling from the mud. NB : This emulsion is generally generally adequate for for bottom hole temperature temperature up to 300 F0 , with respect to filtrate control , and have good rheology if the proper O/W ratio is used and maintained based on final mud weight . NB : The treatments treatments required to maintain maintain an oil mud mud will vary widely widely depending on several several factors : • Drilling rate . • Type of formation . • Temperature. • Weight. • Type of solid control program being used. • Water contamination . • Extremely high bottom hole temperature .
Properties of Brine : Mix brine slug pit or small tank . # Preparing 100 bbl of OBM with O/W ratio 80/20 80 bbl diesel / 20 bbl H 2O Put 20 bbls of H 2O over dead volume of tank (EG: dead volume = 10 bbls) 1. From From drill drill prog program ram need needed ed brine brine with with 30% 30% Ca Cl Cl2 by wt . 2. From CaCl2 chart. 30%CaCl2 by wt ⇒ 149.95 (ppb/H2O) 3. Ca Cl2 (ppb/H2O) * volume of H2O = 149.95*30 = 4498.5lb. # Weight of one sack of CaCl2 = 110 lb. # No of sacks to be added to 30 bbl of H2O = [4498.5/110] = 41 sx. NB: Keep always always an excess lime lime of 5ppb in the the initial emulsion. emulsion. I.E : If dead volume in the mixing tank = 30 bbl. For mixing 100 bbl of OBM 0f O/W ratio 80/20. 5 lb./bbl lime * 130 (total volume) = 650 lb. Total volume =30 bbl dead volume +80 bbl diesel +20 bbl brine. Weight of one sack of lime = 55lb. No of lime sacks sacks =650 /55 = 12 sx. NB : On adding adding E VIS (5 (5 lb./bbl). 130 * 5 = 650 lb. /bbl. Weight of on sack of E VIS = 55 lb. No of E VIS VIS sacks = 650 / 55 = 12 sx. Add E VIS very slowly, add one sack from 10-15 min, and keep gun together with mixing agitator on all the time . NB : Still Still the new emulsion emulsion will not not give the maximum maximum good performance performance except when handling handling at least one complete cycle cycle as the maximum shearing will be at the bit together with the help of bottom hole temperature . NB : Brine activates in OBM are most commonly adjusted using common salt (sodium chloride and calcium chloride) sodium chloride is most often used when salt sections and high activities are expected . For lower activities calcium chloride is most commonly used . In general for all adjustments to activities for sections calcium chloride is preferred because the greater versatility it offers . Oil Mud Calculations :
To determine and calculate the amount of materials required to prepare a given volume of OBM Preparing 100 bbl of OBM : • 15 lb./bbl E MUL (To be mixed in diesel.) • 8 lb./bbl E TON • 2 lb./bbl E WET 1. Determin Determinee density density of oil/w oil/water ater mixture mixture being used. If O/W ratio is 75/25 for example, Set up the following material balance ? 0.75(6.7) + 0.25(8.3) =1 x x = density of mixture PPG . 6.7 = density of oil PPG. 1. = den densi sity ty of wate waterr PPG PPG.. x = 7.1 PPG. This is the initial density of oil/water mixture. 2. Determin Determinee the volume volume of liquid liquid and and amount amount of barite barite needed needed to prepare prepare 100 bbl bbl of mud ? Using the starting formula : SV = [ (35.4-W2) /(35.4-W1) ] * Diesel volume(bbl) SV =starting volume. W1 = initial density of oil/water mixture. W2 = desired mud weight (EG : 16 PPG) SV =[ (35.4-16) / (35.4-7.1) ] * 100 SV = 69 bbls of liquid. Of these 69 bbls , 75% or 51.7 bbls is the volume of oil required, and 25% or 17.3 bbls is the volume of water required to make 100 bbls of mud of weight 16 PPG. The amount of barite is found by : Diesel volume – required volume. X no of sacks of barite to make one bbl b y volume(15 sx) = no of sacks to be added to rise up volume to 100 bbls. (100 – 69 ) * 15 = 465 sx
3.
Determin Determination ation of amount amount of other other oil mud mater materials ials . Determine the amounts of other materials by multiplying the concentration of additives times the number of bbls to be prepared. • 15 lb./bbl (E MUL) * 100 = 1500 • 8lb./bbl (E TON) *100 = 800 • 2 lb./bbl (E WET) * 100 = 200 NB: The mud mud weight will will approach 16 PPG PPG before all the barite is added added because of the volume and density density contributed by OBM OBM materials . About 900 lbs of these materials will occupy one bbl of volume. 4. Determin Determination ation of oil/w oil/water ater ratio ratio from from retor retortt data data : The significance of the O/W ratio has been previously started . To determine the O/W ratio it is first necessary to measure oil and water percent by volume in the mud by retort analysis . From the data obtained the O/W ratio is calculated as follows : % oil in the liquid phase = [% oil by volume / (% oil by volume+H2O by volume)] * 100 . % water in the liquid phase = [% H 2O by volume/(%H2O by volume +% oil by volume)]*100 The O/W ratio = % oil in liquid phase / % H 2O in liquid phase . For example : Retort analysis : 51 % oil by volume . 17 % H2O by volume . 32 % solids by volume . So % oil in liquid phase = [51/(51+17)] * 100 = 75 % % H2O in liquid phase = [17/(17+51)] * 100 = 25 % . NB : # To change O/W ratio : It may become necessary to change the O/W ratio of an oil mud while drilling. If the O/W ratio is to be increased add oil, if it is to be decreased add water. To determine how much oil or water is to be added to change the O/W ratio, the following calculations are made : a. Determ Determine ine pres present ent O/W O/W ratio ratio as as mentio mentioned ned befo before re . b. Decide whether oil oil or water is is to be added. c. Calculate Calculate how much much oil or water water is to be added added for for each each 100 bbls bbls of mud mud .
To increase O/W O /W ratio 80/20: O/W ratio = 75/25 51 % oil by volume 17 % water by volume 32 % solids by volume Using base of 100 bbls of mud . Here are 68 bbl of liquid (oil & water). To get the new O/W ratio we must add oil. The total liquid volume will be increased increased by the volume of oil added but the water will not change. The 17 bbls of water now in the mud representing 25 % of liquid volume , will not represent only 20 % of the final new liquid volume. Therefore : New liquid volume – original original liquid volume = bbls of liquid (oil in this case)to be added. 0.2 X = 17 0.2 = new % of water volume. 17 = old % of water from retort. X = new total final liquid volume. So X = 17 /0.2 =85 bbls. 85 – 68 = 17 bbls of oil to be added. Check the calculations as follows : If the calculated amount of liquid is added what will be the result O/W ratio ? % oil in liquid phase = [(original volume of oil + new oil added) / (original volume + new oil added)] * 100 . = [(51+17) / (68+17)] * 100 = 68/85 * 100 = 80 % so 100- 80 = 20 % water in liquid phase . New O/W ratio ratio =80/20
To decrease O/W ratio 70/30: O/W ratio = 75/25 . 51 % oil by volume . 17 % water by volume . 32 % solids by volume . using base of 100 bbls of mud . There are 68 bbls of liquid in 100 bbls of mud . In this however water will be added and the oil volume will remain constant. The 51 bbl of oil representing 75 % of the original liquid volume will now represent only 70 % of the final liquid volume .
Let X = final liquid volume . 0.7 X = 51. X = 51/0.7 = 73 bbls New liquid volume – original original liquid volume = amount of liquid(H liquid(H2O in this case)to be added. So 73 – 68 = 5bbl of H 2O to be added. % of H2O in liquid phase=[(original H2O vol.+H2O added)/(original liquid vol.+H2O added)]*100 [(17+5) / (68+5) * 100 = 30 % water in liquid phase . 100 – 30 = 70 % oil in liquid phase . So the new O/W ratio = 70/30 . # For example : If the total volume to be changed from 75/25 to 80/20 is 585bbls, multiply the amount of oil to be added(17) by 5.58 to give the total bbls of oil to added to charge the whole volume. 5. Determin Determinee the amount amount of weight weight material material due to effect effect of liquid liquid addition additionss on mud weight weight ? When oil or water is added to change the O/W ratio, the density of the mud will change . (Mud density PPG)(mud volume bbl) + (density of added liquid PPG)(volume of added liquid bbl) = [mud volume bbl + liquid volume bbl)(new mud density PPG). Using 17 bbl of oil to be added to 100 bbl of 16 PPG mud. (16 PPG)(100 bbl) + (6.7 PPG) (17 bbl) = (100 +17 bbl) X X = new mud density PPG . X = (1600+114) /117 = 14.65 PPG. The same calculations can be made for any liquid or solid which may be added to the mud as long as the material balance takes from V1 D1 + V2 D2 = VR DR NB : The volume and density units must be constant . NB : V1 + V2 = VR . Example : If we have two fluids of known volumes and densities . The resulting volume and density can be calculated as follow :
Fluid # 1 Volume = 210 bbl Wt =16 PPG. (16) (210) + (14.5) (14.5) (150) (150) = VR DR VR = 210 +150 = 360 bbl. [16] [210] + [14.5] [150] = 360 D R DR =[3360 + 2175] /360 = 15.375 PPG.
Fluid # 2 Volume = 150 bbl Wt = 14.5 PPG.
The volume of the mud of known density required to change of another mud to a desired value can be calculated as follows : How much 13.6 PPG mud must blended with 410 bbls of 16 PPG mud so that the resulting mixture will have a density of 15.2 PPG? [410][16] + V2[13.6] = [410 + V 2][15.2] 6560+ V2[13.6] = 6432+ V2][15.2] 6560.6232 = V2[15.2-13.6] V2 =328/1.6 = 205 bbl . Displacement procedures : When ever ever possible possible displace displace the the water water base base mud with with OBM OBM whilst whilst in in the casing casing.. If allowable allowable , the OBM OBM should should have a density density heavier heavier than the the water water base fluid fluid to be displaced. displaced. Decrease Decrease the viscosity viscosity of the water water base fluid fluid if in casing dilutio dilution n and treatment treatment with with a deflocculant deflocculant (such (such as ferrochrom ferrochromee , lignosulphonate) FCl can be used . If the hole is open, heavier treatments with (FCl) will be necessary in general the weight reduction from a large dilution can not be treated . It is desirable the gel strength and yield point of the water based fluid be as low as possible to provide for the cleanest and sharpest interface between the two fluids . 4. With about about 20 bbls of of OBM prepar preparee a viscous viscous spacer spacer and and pump pump this first first . 5. Pump the the OBM slowly slowly (5 bbl/min) bbl/min) to to produce produce the least least inter inter merging merging of the the two fluids fluids . 6. Rotate Rotate the drill drill pipe at + , -,(60 RPM) RPM) while displac displacemen ement. t. This will will prevent prevent the water water based fluid fluid from gelling gelling and will will also aid in removing the water based fluid from all parts of the hole. 7. If the spacer spacer has has not been been not contamin contaminated ated it may may be incorpor incorporated ated back back into the the OBM OBM . NB : If the changeover of fluid has taken place in the open hole the filter filter from the water based fluid may plug the shale shaker shaker during the first circulation . If this happens the screens should be with oil and brushed . Also the OBM should be carefully observed for signs of water wet solids and treated with E WET if required. 1. 2. 3.
Recommended Properties and Control : Rheological Control :
The polar interaction between charged clays and polymers that take place in a water based fluid are absent in the non polar oil phase and only the relatively weak hydrogen bonding can occurs. These weak forces are readily broken by heating the medium. So the viscosity tends to be substantially reduced by temperature increases. NB : The optimum range of the factor of a properly properly maintained OBM is normally normally in the range range of 0.75 – 0.85 . The plastic viscosity is affected by 1. Qual Qualit ity y of of oil oil and and wat water er . 2. Qualit Quality y of sol solids ids , and size size of of the the solid solidss . 3. The The temp temper erat atur uree .
High values values of PV and YP are mainly due to exces excessive sive solid concentration concentrationss or an unfav unfavorabl orablee O/W ratio. The solids may be removed by fine screens or centr centrifuga ifugation tion . If this have no effective results dilution with either diesel or fresh volume of OBM is recommended . The YP is less affected by temperature than PV , but is related to the solids content and water content. Very high values of YP may be due to water wet solids in the drilling fluids. This will result in high yield and high gel . Oil wetting agents used to reduce the YP. derived from water wet solids. Dilution may also be required to lower YP .
Settling of barite may also occur , this is treated by adjusting gel strength with oil wetting agent (E WET). Also temperature will have an effect on suspension properties. # Separation of the lighter oil to the surface of emulsion fluid might occur need to add emulsifiers with presence of good mixing and maximum shearing.
NB : Always density density is measured of the top and bottom bottom halves of the fluid . The settling factor is (SF) given by the following formula : SF = (Wt of the bottom half) / (Wt of the bottom half + Wt of the top half) If no settling is taking place the value will be within o.5 . The values of less than o.55 are satisfactory for packer fluids and volume of 0.55 is acceptable for drilling fluids. Gel strength of 4-5 lb./100 ft 3 initial and 6-8 lb./100 ft 3 10 minutes gel. Will suffice normally for barite suspension in most mud densities. These vales can be obtained by addition of E VIS (3-5 lb./bbl). The viscosity effect on oil base mud depends on several factors : 1. Concen Concentra tratio tions ns of emulsi emulsifi fiers ers . 2. Emul Emulsi sion on sta stabi bili lity ty . 3. Mud density. ty. 4. Soli Solid d dist distri ribu buttion. ion. NB : Emulsifiers or oil wetting additives additives should be added at the same time while adding E VIS to obtain the required YP . Hydraulic Control : The effects of temperature and pressure on the rheological properties of the OBM, have to be taken into account before the normal equations are used . To calculate the critical velocities , swab and surge pressures, and pressure losses in the drill string and annulus . As a first approximation is assumed that the viscosity changes of diesel oil with temperature and pressure can be applied to the oil based emulsion. This assumption assumption has more accurate accurate applications in systems with with high O/W ratio ratio and low solid concentrations . The relationship between viscosity and temperature and pressure is given in figure 7. From this data a correction factor can be calculated that can be applied to the rheological data determined at the flow line . To do this the down hole temperature and pressure have to be estimated . temperature) * 3] /4} + Ambient temperature. • Maximum circulation temperature = {[(BHT – Ambient temperature) • The hydrostatic pressure at the point of highest temperature temperature occurs three quarters of the way down the hole. Hydrostatic pressure at maximum temperature = depth(ft) * Mwt(PPG) * 0.039 ⇒ psi Or = depth(ft) * Mwt(kg/l) *0.075. This data of temperature and pressure is then used with figure 7 to obtain the viscosity of the diesel oil at these conditions . Average viscosity of diesel oil = [flow line viscosity +down hole viscosity] / 2 This average viscosity of diesel oil is then compared with viscosity of diesel at the temperature at which the measurements were taken to drive the correction factor. Correction factor =average viscosity of diesel / viscosity of diesel at measurement temperature. EG : Flow line temperature = 75 C o (167 oF). Bottom hole temperature = 182 Co (360 oF). Ambient temperature = 20 Co (68 oF). # Step 1 Maximum circulation circulation temperature = (182-20)*0.75 (182-20)*0.75 +20 =141.7 Co (287 oF). # Step 2 At depth 20,000 ft (6096 m) the mud density = 18 PPG ( 2.16 kg/l). So pressure at a maximum circulation circulation temperature = 20,000*18*0.039 =14,040 psi. Viscosity of diesel @ 141.7 C o = 14.04 psi.
From figure 7 = 1.3 cps . # Step 3 Rheology determined determined @ 50 Co (122 oF). viscosity of diesel @ 50 Co = 1.9 cps . from figure 7 viscosity of diesel at flow line. From figure 7 @ 75 C o and o psi =1.25 cp Average viscosity = (1.25 + 1.3) /2 = 1.28 cps. Correction factor for VG data =1.28 / 1.9 = 0.67 .
Trouble shooting One of the most important parameters of a drilling fluid is the rheology . However it is affected by many other parameters such as solids, O/W ratio and oil wetting of solids. # Solids : solids do not present such a problem with OBM as in water based fluid for two main reasons : 1. The solids solids in OBM OBM can not not be hydrated hydrated and and thus soften soften and and disperse disperse into into the fluid fluid . 2. In oil continues continues fluid ,polar ,polar interactions interactions between between charged charged solid particles particles can not take place because because the medium will not polarize polarize or conduct electricity .
Solids behave as essentially inert and OBM h as a higher tolerance to solids than water w ater based fluids. Operational aspects : In general the contamination of any mud with solids will will cause : Increase drilling fluid maintains cost . 1. Difficul Difficulty ty in maint maintaini aining ng proper proper rheol rheologica ogicall properti properties. es. 2. Redu Reduce ce pen penet etra rati tion on rat rates es . 3. Decrease Decrease bit life and incre increase ase wear wear of pump pump parts parts . 4. Increa Increase se freque frequency ncy of diffe differen rentia tiall stickin sticking g. 5. Increa Increase se circu circulat lation ion pre pressu ssure re loss losses es . Effect of Solids on PV : The increase of solids increases PV due to mechanical friction between solid particles in the drilling fluid . PV depends primarily on size shape and number of solids in the fluid. Effect of Solids on YP and Gel Strength : As YP and gel strength the degree of attractive forces between particles in the fluid. These attractive forces are related to the distance between the particles particles . Therefore Therefore the increase increase of solids increases increases YP and gel gel strength . However chemical treatment , dilution , and mechanical removal of solids are done to overcome the continuos of PV and YP and gel strength due to build up of percentage of solids. The removal of very fine particles produces a greater reduction in viscosity than does the removal of an equivalent volume of coarser solid due to the difference area. NB : 1. The smaller smaller the partic particle le size the more more pronounce pronounced d the effect effect on the fluid fluid propertie propertiess . 2. The smaller smaller the partic particle le size the more more it is to remove remove or control control its its effects effects on the fluid. fluid. NB : In general high PV , YP and gel may result in thick filter cakes which by turn will result in over pulls in trips . Also high pump pressure due to high high pressure losses. losses. High annular pressure losses may result in severe hole erosion. NB : The drilling fluid has has a tendency to thicken when left left for a long time time period without without circulation . Treatment
A. 1. 2. 3. 4. 5. B.
By mean solid removal removal equipments equipments remove drilled solids solids as soon as they are generated . Use small shaker screens (120 mesh if possible) it is recommended not not to use small mesh screen for a long period. period. Desilter . Desander . Mud cleaner . Centrifuge . If excessive excessive solids solids do do build up up then the the whole whole mud volume volume must must be diluted diluted .
Water wet solids : • The OBM drives many of its advantages from the fact that the formations only contacted with oil. • A rule of thumb : the vapor pressure of the emulsified water droplets is also adjusted so that the water remains in the emulsified fluid .
•
However , sometimes drilling formations with very high porosity and at the same time impermeable and keeping in its pore spaces high percentage of water . That kind of formations will produce water wetted cuttings , that can interact into mud if there is any lack in the percentage of emulsifiers or oil wetting agent in the mud . This result in polar interactions between water wetting particles and associated brine droplets in the mud . That will give rise to : 1. Vis Viscos cosity ity , YP YP and and gel str streng ength. th. 2. Decr Decrea ease se emul emulsi sion on stab stabil ilit ity y. 3. Incr Increa ease se filt filtra rati tion on . 4. Mushy struc structure ture of cuttin cuttings gs which which will cause cause blinding blinding and and plugging plugging shaker shaker screens screens . 5. Sever Severee settl settling ing fills fills afte afterr trips trips . 6. Mud Mud has has a dul dulll loc lock k. 7. Thicking Thicking of of the fluid fluid may may occur occur depending depending on on solid solid concentr concentration ationss . Treatment : 1. the problem can be overcome overcome addition of higher levels of emulsifiers (E MUL + E CON) CON) which increase combination combination between between diesel and water , also make an oil film around wetted cuttings , thus retain stability stability of fluid and give rise to the basic filtration control of the drilling fluid. 2. Add oil wetting agent to give the drilling fluid extra extra stability and surrounds surrounds (wet) the water water wet particles resulting from wet formations . Also oil wet the formation itself itself and thus decrease the invasion of water wet particles from getting getting into drilling fluid. It also acts as a thinner and thus helps the dispersion and suspension of invaded water wet particles . thus retain good rheology to drilling fluid . Electrical stability : Electrical The inert nature of the fluid is derived from the fact that the water present is tied up in the form of droplets , stabilized by a complex layer of surfactants . The stability is affected by the size of the droplet which in turn is related to the concentration of emulsification reagent and the shear imparted into the system. The smaller the droplet the greater the stability and resistance to coalescence of drops. The stability is measured by application of a DC voltage across two terminals immersed in the fluid to pass a certain current. The stability is often measured in volts. A value of 400 volts is generally considered adequate , but higher is easily obtained and characteristic characteristic of the strong emulsification system . The emulsification stability stability can be increased by addition of E MUL and E CON either single or together in conjunction with mixing under maximum shear conditions . Filtration control : The emulsified water droplets act as colloide sized solids that combines with the other solids in the fluid to form a very effective filter cake .
The good filter cake and filtration control are highly affected by : 1. The The str stren engt gth h of emul emulsi sion on . 2. Type Type and and natu nature re of soli solids ds . 3. Visc Viscos osit ity y of of oil oil emul emulsi sion on . To obtain a measurable quantity of filtrate , this is done under high temperature(300 temperature(300 F o) and high pressure (500 psi). The HT HP fluid loss should be free of water or traces of emulsion and is usually low . The filtration rate will be lowered by addition of E CON and filtration reducer (E TON) However this product is used when required an extremely low filtration for low density fluids Alkalinity : The alkalinity of drilling oil fluids should be kept in the range of 2-4 cc. Is important to maintain this range , regardless of the other parameters required required due to ionic nature of the various various electrolytes electrolytes and because of different different additives especially E CON CON emulsifier emulsifier which functions more effectively in that range . This is maintained by adding lime . Drilling different salts , KCl, Na CL, Mg Cl 2, Ca Cl2 and encountering brine water flow : Effects : 1. Decr Decrea ease se sta stabi bili lity ty . 2. Salt is very hygroscopic and tends to coagulate the water droplets droplets which in turn turn accelerates water water wetting of barytes and certain other mud constituents . 3. Salt also affec affectt the oil oil –mud emulsion emulsion chemist chemistry ry . 4. Lowe Lowerr vis visco cosi sity ty . 5. HT HP fluid fluid loss loss may increa increase se ,and water water show show up in the the filtrate filtrate . Treatment : 1. Add emulsifiers emulsifiers which ensure that the oil emulsion emulsion show a good resistance resistance to salt contamination. contamination. I.E : Higher levels of E MUL and E TON may be required and attention should be paid to removal of salt crystals by screening . 2. If a brine flow flow is encountered encountered the O/W ratio ratio should be restored restored by addition of diesel diesel oil and further further emulsifiers emulsifiers . 3. Lime Lime additions additions may may be required required to counte counterr the acidity acidity of the the brines brines .
Cementing / Cement Contamination : Can only be a problem if lot of wet cement is drilled. Effects : 1. Viscos Viscosity ity (PV (PV & YP) YP) incr increas eases es . 2. Wa Wate terr wet wetti ting ng . Treatment : Addition of E MUL + E TON + E WET . Cementing Procedures : Cementing with an oil mud in the hole requires special precautions as the mixing oil mud and cement slurries can produce a highly gelling un pumpable mass . This problem necessitates a neat separation of these two systems , and that is done by an effective spacer which has two main properties : a. separa separate te compl complete etely ly betwe between en OBM OBM and ceme cement nt . b. Remove the oil film on the casing and convert convert the surface to a water wet state, state, and thus improving improving the cement cement bond . • The soccer can be mixed from fresh ,sea, or brine . • The viscosity can be adjusted to produce a turbulent flow if required . • The cement should be replaced at the maximum possible pump rate (regardless of whether turbulent floe can be achieved ). Reciprocating and rotation of the casing will also significantly improve the displacement efficiency . H2S contamination : An oil base fluid is normally suited to accept invasion of H 2S . In water base fluids . Such invasion creates a problem due to hydrogen sulfide embrihelmentof steel work and drastically changes to chemistry of the fluid due to reaction of alkalis . In OBM the steel work is protected by the continuos oil phase and H 2S dissolve in oil phase(to be removed by degaser) . Side Effect : 1. Darke Darkenin ning g of the the mud mud . 2. Decrease Decrease alkali alkalinity nity due due to the acidic acidic nature nature of H2S and its reaction with lime . 3. Possible Possible decrea decrease se emulsion emulsion stabilit stability y. Treatment : Addition of lime to maintain alkalinity above 2 cc . CO2 Contamination : (acidic gas) Effect : 1. Decr Decrea ease se in alka alkali lini nity ty . 2. Decr Decrea ease se emul emulsi sion on stab stabil ilit ity y. 3. Continuos Continuos intrusion intrusion will will increa increase se viscosity viscosity (YP & Gel stren strength) gth) . Treatment : Addition of lime to maintain alkalinity in the optimum range . Gas Cutting : Effect : 1. Sett Settli ling ng of bary baryte tess . 2. Weakening of the emulsion stability . Treatment : 1. Addi Additi tion on of E MUL MUL + E CON CON . 2. Addi Additi tion on of E TON TON . 3. Addi Additi tion on of E WET WET . 4. Repl Replac acee by by deg degas aser er . NB : Overtreating Overtreating with surf-cote surf-cote can destroy destroy viscosity beyond beyond repair. Prior to treatment pilot testing is is imperative .
Problem 1.
Low emulsion stability
2. Water wetting of solids.
Indications Dull grainy appearance to mud. High HTHP fluid loss. Free H2O in HTHP filtrate. Barite settling out. Blinding of shaker screens. Extreme cases can cause water wetting of solids
Flocculation of barite on sand – content test. Sticky cuttings. cuttings. Blinding of shaker screens. Settling of barite. Dull, grainy appearance of mud. Low ES. Free H2O in HTHP filtrate.
3. H2O contamination
Weight drop, change in O/W ratio
High High filt filtra rati tion on
High High HTHP HTHP filt filtra rate te with with increasing free H2O. low ES. Fill on connections and trips. Sloughing shale.
4. High viscosity
High PV, high YP, increasing funnel viscosity. Increasing retort solids. Increase in water content.
Cause 1. Low emulsifier. 2. 3.
Super uper-s -sat atur urat ated ed with CaCl2. Water fl flows
4. Mixing mud at mixing plant
1. inadequate emulsifier 2.Water-base mud contamination. 3. Super-saturated Super-saturated with CaCl2.
Treatment 1. Add CARBO-MUL. Add CARBO-TEC and lime if CARBO-TEC system 2. Dilute back with fresh H2O and add CARBO-MUL. CARBO-MUL. 3. Add CARBO-MUL. Can also add CARBO-TEC and lime if CARBO-TEC system. 4. Maximize shear. Check electrolyte electrolyte content(the higher the content, the harder the emulsion is to form)
1. Add CARBO-MUL and SURF-COTE, and diesel 2. Same as 1. 3. Dilute with H2O and add CARBO-MUL.
Add diesel, CARBO-MUL HT, barite.
1. Low emulsifier content 2. Low concentration of fluid loss control additives. 3. High bottom hole temperature
1. Add CARBO-MUL. Add CARBO-TEC and lime if a CARBO-TEC system 2. Add CARBO-TROL A-9 and/or CARBO-TROL.
1. Low emulsifier content 2. Water contamination. 3. Over treatment with emulsifiers, especially CARBOTEC.
1. Dilute with oil, maximize solid control equipment .
3. Add more CARBO-MUL. Add CARBO-TEC and lime. Convert to CARBO-TEC system. Add more CARBO-TROL A-9 and CARBO-TROL.
2. Add emulsifiers. If severe, also add SURF-COTE. 3. Dilute with oil.
5. High solids
Retort analysis, calculations
1. Reduce of sh s haker screens, dilute with diesel
6. Oil separation
Oil on surface
1. Agitation, add CARBO-GEL or CARBO-VIS
7. Emulsion breaking
Water in filtrate, low electrical stability.
1. Add CARBO-MUL, CARBO-MUL HT, lime.
8. Low alkalinity
Low stability, CO2 & H2S intrusion
1. Maintain 5-7 lb./bbl lime.
9. Sloughing shale
Fill on connections and trips. Torque and drag. Increase of cuttings across shaker.
1. Drilling under balanced. 2. Excessive filtrate. 3. Inadequate hole cleaning. 4. Activity too low
10. Barite settling
Low YP and gels. Settling of barite in heating heating cup or viscosity cup.
1. Poor oil wetting of barite. 2. Inadequate suspension. 3. Low ES, high HTHP.
1. Increase mud weight. 2. Add emulsifiers. Add CARBO-TROL A-9 and/or CARBO-TROL. 3. Add CARBO-GEL to increase YP. 4. Adjust CaCl2 content of internal phase so match formation activity. 1. Add emulsifiers and/or wetting agents. Slow addition of barite. 2. Add CARBO-GEL or viscosifing polymer. 3. Add emulsifier.(i.e.; CARBO-GEL, CARBO-VIS or water )
11. Drilled solids appear gummy
Shale cuttings absorbing water by hydration forces
1. Increase salinity to 350000 PPM with CaCl2.
12. Undissolved CaCl2 or NaCl
Drop in ES, high Cl content in H2O phase.
1. Add H2O to dissolve Salt, then add CARBO-MUL + CARBO-MUL HT + lime. New mud without salt in H2O phase may be blended.
13. Lost circulation
Pit volume decrease, loss of returns.
1. Hydrostatic pressure is greater greater formation pressure
1. Add mica or plug. Never add fibrous or Phenolicresin materials. If possible, reduce mud weight. Add MILFIBER, MILFIBER, or calcium carbonate.
14. problem mixing mud at mixing plant
Poor emulsions stability. stability. Barite settling. Dull, grainy appearance to mud. Mud very thin with no yield or gel strengths.
1. Inadequate shear 2. Very cold 3. Poor wetting of barite 4. High electrolyte content. Normally greater than 350000 PPM. 5. Surface contamination possible if using using CaCl2 brine that has been used as completion or work over fluid
1. Maximize shear 2. Lengthen mixing time 3. Slow additions of barite. Add CARBO-MUL if severe, add small amount of SURF-COTE. 4. Dilute back with fresh H2O. once emulsifier is formed, can add additional CaCl2 to obtain desired activity . 5. Pilot test with known CaCl2 brine to determine if problem does exist. exist.
Lost Circulation : Lost Circulation material like mica or nut plug (fibbers in the worst case)can be added directly to the mud. • Lost circulation materials weaken the emulsion and cause water wetting tendencies . Therefor it is required to add a sufficient of emulsifiers (E MUL + E CON) and oil wetting agent (E TON) to a system containing lost circulation materials . Diesel M plug : prepare slurry of 50-60 bbls (8-10 m3) with flowing materials . A. Dies Diesel el M bari barite te plug plug : Mixing order is as follows; Diesel, Diesel M, Barytes, Barytes, and E TON (SG of barites barites 4.25) .
TABLE B. Dies Diesel el M-Si M-Side deri rite te plug plug : Consideration concerning the pay zones , may require an acid soluble weighting material, a siderite (Fe CO 3) . The mixing order is as follows; Diesel oil, Diesel M, I Dwate and E MUL +E CON . In both system s, ensure that adequate mixing has taken place before either weighting agent is added . Spotting the Pill : 1. Dete Determ rmin inee the the thi thief ef zone zone . 2. The pipe pipe should should be pulled pulled to the the casing casing while while mixing mixing the pill pill if possibl possible. e. 3. The pill pill is is mixed mixed to the the desir desired ed weig weight ht . 4. The slurr slurry y is pumped pumped into the the open open hole or above above the the thief thief zone zone . 5. Allo Allow w a sett settin ing g time time for for pil pilll . 6. The blow out out presenter presenterss are closed closed and a slight squeeze squeeze press press is applied applied [200-400 [200-400 PSI PSI (13.5-25 (13.5-25 atm)] atm)] . 7. By pumping pumping slowly and and hesitating hesitating for press press build-ups build-ups and bleed-of bleed-offf a successful successful squeeze can can be accomplishe accomplished d. 8. After After a back pressure pressure sufficien sufficientt to withstand withstand proposed proposed mud wt wt is obtained obtained and held held for 2-4 hours hours . 9. Drilling can can be resumed resumed , circulation circulation should be restored with a very very slow pump pump rate after after getting back to bottom bottom . NB : This technique is used used where partial or complete losses losses are occurring occurring to induced fractures fractures . Blow Out / Flow : Setting of a Barytes in oil plug : This technique is used in oil mud against underground blow outs or to plug the bottom of a hole quickly without cement . 1. Calculate the volume(bbls or m3) for 300 ft or 100 m receptively of settled barite in the oil plug including estimated estimated hole wash outs . 2. If it is flowing flowing down down hole use E MUL + E ECON CON as oil wettin wetting g dispersant dispersantss . 3. Barytes Barytes is added to increa increase se the weight weight of oil plug up to 21 PPG PPG (2,52kg/ (2,52kg/l) l) Preparation of an oil plug slurry : In bbls : E MUL Oil wetting agent Barite Slurry volume (Lb.) (lbs.) (lbs.) (bbls) 2 2 1060 1.52 In m3 : E MUL (Lb.) 5
Oil wetting agent (lbs.) 5
Barite (kg) 3025.24
Slurry volume (m3) 1.52
CHEMICAL ANALYSIS OF OBM : Whole Mud Alkalinity : 1. Add 100 cm3 of 50/50 xylene /IPA solvent to a 400 cm 3 beaker or titration vessel. 2. Fill a 5 cm 3 syringe with whole mud past the 3 cm3 mark . 3. Displace 2 cm 3of whole mud into the titration vessel . 4. Swirl Swirl the the mixt mixture ure until until it it is homo homoge genou nouss . 3 5. Add 200 cm disttled water . 6. Add 15 drop drop Ph Ph Ph indic indicato atorr solut solution ion .
7.
While stirring stirring rapidly rapidly , slowly Titrate Titrate with with O.I.N O.I.N sulfuric sulfuric acid until pink color just disappears disappears . continue stirring stirring and if no pink color reappears within one minute , stop stirring . 8. Let the sample sample stand for five minutes. If If no pink color color reappears , the end end point has been reached . Record the volume of acid used. If oink color returns , Titrate with acid a second time .If a pink color returns after the second titration , Titrate with acid a third time and call a total volume of acid used for all three titrations the end point . 9. Calcul Calculate ate the whole whole mud mud alka alkalin linity ity : Pom =0.1 N sulfuric acid, cm 3 / mud sample cm3 = 0.1 N sulfuric acid, cm 3 / 2 cm3 To convert this volume to lb./bbl , Ca (OH) 2 lime multiply by 1.295 . If CaO (quick lime) is used to activate the emulsifier, the conversion factor to lb./bbl is 0.98 . Whole Mud Chloride : 1. Using the same same sample that used used for the alkalinity, alkalinity, procedure, procedure, make sure the mixture mixture is acidic acidic by adding 1-2 or more 0.1 N sulfuric acid. 2. Add 10-15 10-15 drops drops of potassium potassium chrom chromate ate indicat indicator or solution solution . 3. While stirring stirring rapidly , slowly slowly Titrate with with o.282 N silver silver nitrate until until a salmon pink pink color remains stable for at least one minute. If a question exists as to if the end point has been reached , it may be necessary to stop the stirring and allow separation of the two phases to occur . 4. Calculate the whole mud chloride using the volume of 0.282 N AgNO3 : Clom =10,000(0.282 N AgNO3 , cm3) / oil mud sample, cm 3 . = 10,000(0.282 N AgNO3 , cm3) / 2 .
Whole Mud Calcium: Add 100 cm3 of 50/50 xylene /IPA solvent to a titration vessel. Fill a new 5 cm 3syringe with whole mud past the 3 cm3 marsh . Displace 2 cm 3 oil mud into titration vessel . Cap the the jar jar tightly tightly and and shake shake vigoro vigorously usly by hand for one one minute minute . 3 Add 200 cm distilled or deionized water to the jar . Add 3 cm3 1N sodium hydroxide buffer solution . Add oil to 0.25 g calver 2 to indicator powder . Recap the jar tightly, tightly, shake vigoursouly vigoursouly again for for two minutes, minutes, set jar a side side few seconds seconds . If If a reddish color appears appears in the aqueous phase (lower) calcium is present. Continue the test. 9. Begin Begin stirrin stirring g withou withoutt mixing mixing upper and lower lower phases phases . 10. Titrate slowly by adding EDTA (versenate). When a distinct color change from reddish color to blue-green color occurs , the end point is reached. reached. Read the volume of EDTA titrated. 11. Calculate the whole mud calcium using the volume of EDTA : Caom = 4,000(0.1 M EDTA cm 3) / oil mud sample cm 3. = 4,000(0.1 M EDTA cm 3) / 2 cm3 1. 2. 3. 4. 5. 6. 7. 8.
A) WHOLE MUD CALCULATIONS THE WHOLE MUD ALKALINITY 0.1N sulfuric acid, cm 3 Po m = = 3 Mud sample cm
0.1N sulfuric acid, cm 3 (1) 3
2 cm
THE WHOLE MUD CHLORIDE 10000 (0.282 N silver nitrate, cm 3) Clo m =
(2) Oil mud sample
10000 (0.282 N silver nitrate, cm 3) Clo m = 2.0 cm3
THE WHOLE MUD CALCIUM 4000 (0.1 M EDTA cm 3) Ca o m =
(3) Oil sample, cm
3
4000 (0.1 M EDTA cm 3) Ca o m = 2.0 cm3
1. Tota Totall lime lime con conte tent nt:: The total lime content represented as lime hydrate , Ca (OH)2, is : Lime lb./bbl = 1.295 (Po m) (4) If quick lime, is CaO is used to activate the emulsifier, the total quick lime is: Lime lb./bbl = 0.98 (P o m) (4a) 2. To Tota tall cal calci cium um co cont nten ent: t: The total calcium content is: Ca o m = 4000 (VEDTA) (5) Where Ca o m = mg Ca++/ L VEDTA = cm3 0.1 Molar EDTA/cm3 of mud. 3. To Tota tall chl chlor orid idee cont conten ent: t: The total chloride content is: Clo m = 10000 (VSN) (6) Where Clo m = mg Cl-/L VSN = cm3 0.282N silver nitrate/cm3 of mud. 4. Total CaCl2 and NaCl content: The chloride ion associated with CaCl2 based upon the Cao m analysis is: Cl CaCL2 = 1.77 (Cao m) (7) Where Cl CaCL2 = mg Cl/L of mud from CaCl2 NOTE: If CaCl2 ≥ Clo m then assume that only CaCl2 is present in the mud and no NaCl is present, proceed to Eqn. 13 and skip Eqn. 8 through 12. CaCl2 o m =2.774 (Cao m) Where CaCl2 o m = mg CaCl2/L of mud CaCl2 salt = 9.17 X 10-4 Cao m Where CaCl2 salt = lb. calcium chloride per barrel of mud ClNaCl = Clo m – ClCaCl2 Where ClNaCl = mg Cl/L of mud from NaCl. NaClo m = 1.65 (ClNaCl) Where NaClo m = mg NaCl/L of mud
(8)
(9)
(10)
(11)
NaClsalt = 3.5 X 10-4 (NaClo m) Where NaClsalt = lb. sodium chloride per bbl of mud. Omit Eqns. 13& 14
(12)
If the test Eqn. 7 indicates that all of o f the chloride ions generated from CaCl2 , the following equations are used: CaCl2o m = 1.57 (Clo m) (13) Where CaCl2o m = mg CaCl2 / L of mud. CaCl2 salt = 3.5 X 10-4 (CaCl2 o m) (14) Where CaCl2 salt = lb. CaCl2 per bbl of mud.
B) AQUEOUS PHASE SALT CALCULATIONS Accurate salt calculations prevent the super saturation of the brine with CaCl2, which can lead to severe water wetting. The percent by volume solids, as determined by the distillation retort, should be adjusted for the calculated salt volume which will be retained in the retort assembly. This correction can be accomplished with simple calculations, assuming that accurate chloride and reading data are used. The following equations are designed to calculate the quantity of NaCl and CaCl2 in the aqueous phase of the CARBO-DRILL Systems.
100 (CaCl2 o m) Wc =
(15) CaCl2 o m +NaClo m + 10000 (Vw)
Where Wc = wt % CaCl2 in brine. Vw = volume % retort water. CaCl2 PPM = 10000 (Wc)
(15a)
100 (NaClo m) WN =
(16) CaCl2 o m +NaClo m + 10000 (Vw)
Where W N = wt % NaCl in brine. NaClPPM = 10000 (WN) Check mutual solubility of NaCl and CaCl2 or use Figure 2. WN max = 26.432 – 1.0472 (Wc) + 7.98191 (10-3) (Wc)2 + 5.2238 (10-5) (Wc)3 Where WN max = maximum wt % NaCl in CaCl2/ NaCl brine at 25C (77F)
(16a) (16b)
1. MUTUAL SOLUBILITY Check figure 2 or Eqn 16b to determine the weight percent of sodium chloride, W N, that is totally soluble in the CaCl2 /NaCl brine solution at 25 C (77F). (77F ). if the calculated W N is not totally, the results a portion of the NaCl is a solid in the oil base fluid. Also, if the W N is not totally soluble. The results of the Eqn 1 5 and 16 are not n ot correct. They must be recalculated using a fraction of W N as the NaCl o m , until the ratio of W Nmax / W N is greater than 0.95. the following steps are used to determine more accurate salt solubilities .
Calculate the NaCl ratio to determine the accuracy of W N : WN max NaCl ratio = (16c) WN Where NaCl ratio = the ratio of the maximum wt % NaCl to the calculated wt % NaCl in the brine. If NaCl ratio is greater than 0.95 proceed to Eqn. 17. Otherwise, the value for Wc (Eqns. 15 & 15a), W N (Eqns. 16 & 16a). and W N max (Eqn. 16b) must be recalculated using the value NaClo m as a new value calculated by: NaClo m n = NaCl ratio (NaClo m) (16d) Where NaClo m n = the new NaCl o m to be used in Eqns. 15 through 16b. After substituting the new NaClo m n in Eqns. 15 through 16b, recalculate the NaCl ratio (Eqn. 16c) using the new values. If NaCl ratio is still less than 0.95 the above procedure must be repeated, as shown in the example ex ample on page 334. Use only the soluble NaCl portion from the graph or equation iterations as the value of W N in future equations. The remaining salt will be calculated as a solid in the following analysis: PB = 0.99707 + 6.504 (10-3) (WN) + 7.923 (10-3) (Wc) + 8.334 (10 -5) (WN) (Wc) + 4.395 (10 -5) (WN)2 + 4.964 (10-5) (Wc)2 (17) Where PB = brine density, g/cm3. NOTE: The density of single -salt brine can be found using the values or equations found in the engineering data chapter, section 4 (salt tables) a. mg/L salt weight percent units are based upon the density of the brine, as well as a s the salt content. The salt concentration , expressed as mg/L is: CaCl2mg/L = 10000 (Wc) (PB) (18) NaCl mg.L = 10000 (WN) (PB) (19) **************************************FIGURE*******************************************
C) SOLID CALCULATIO CALCULATIONS NS As mentioned previously, the solids content, measured from the retort distillation procedure, must be corrected for the salt content of the brine that remains in the retort assembly. The corrected volume % brine is: 100 (VW) VB = (20) PB [ 100 – (W N + Wc) Where VB = volume % brine The corrected volume % solids are: Vs = 100 – (V O + VB) (21) Where VS = volume percent % corrected corrected solids. VO = volume retorted oil. The solids in CARBO-DRILL Systems consist of low density solids, usually drill solids, and high density solids, generally MIL-BAR or DENSIMIX. [ 100 (MW)] – [(VO) (PO) ] – [ (VB) (8.345) ] PS =
(22) 8.345 (VS)
Where PS = average density of solids, g/cm3 PO = oil density, lb./bbl MW = drilling fluid density, lb./gal.
The average density of suspended solids can be divided into the volume and weight of high density and lowdensity solids. The volume % high-density solids are:
PS - PLDS VHDS =
X VS
(23)
PHDS – P LDS
Where VHDS = volume % high density solids. PHDS = destiny of high solids, g/cm3 P LDS = density of low-density solids, g/cm3 The concentration of high density is: MHDS = 3.5 (PHDS) (VHDS) Where MHDS = high density solids lb./bbl The volume of low-density solids is:
(24)
V LDS = VS - VHDS Where V LDS = volume percent of low density solids. The concentration of low-density solids is: M LDS = 3.5 (P LDS) (V LDS) Where M LDS = low-density solids, lb./bbl.
(25)
(26)
D) OIL/WATER RATIO CALCULATION CALCULATIONS S The oil/water ratio relates the oil and fresh water fractions as a percent of the liquid retort fraction. The oil/brine (salt-content corrected water) ratio relates the liquid fraction of the mud as ratio of oil and brine fractions. The oil/brine ratio is the most meaningful ratio. Since it relates more closely the liquid fractions of the drilling fluid. Oil/brine ratio is important when engineering most CARBO-DRILL Systems, in that it can have a major effect on viscosity and/or filtrate loss. The oil/water ratio is calculated as follows: 100 (Vw) WR =
(27) VO +Vw
Where WR = water % in the ratio. OR = 100 – WR Where OR = oil % in the ratio. The more accurate and useful u seful ratio is the oil/brine ratio . the oil/brine ratio is calculated as follows:
(27a)
100 (VB) BR =
(28) VO +VB
Where BR = brine % in the ratio. OR = 100 – BR (28a) 1. Changing Oil/Brine Ratio: it may be necessary, at some time , to change the oil/brine ratio of the CARBO-DRILL System. The simplest calculation to make is increasing the oil/brine ratio , since only oil is added. To increase the oil/brine ratio with additions of oil:
R O
[
VO + VB 100
] - VO
FO =
X Volsys
(29)
R B
Where FO = volume of oil, bbl. R O = required oil ratio. R B = required brine ratio. Volsys = system volume. To decrease oil/brine ratio with the addition of brine:
R B
[
VO + VB 100
FB =
] - VB X Volsys
(30)
R O
Where FB = volume of brine, bbl. Addition of fresh water will increase the controlled activity of the system . if brine is not available , CaCl2 salt should be added to the drilling fluid when decreasing the oil/water ratio with fresh water . the quantity of calcium chloride necessary to maintain a constant c onstant activity when adding fresh water is as follows:
H2O, gal/bbl X FB FW =
(31) 42
CaCl2 add = CaCl2, lb./bbl X FB (31a) Where FW =volume of water, bbl. H2O, gal/bbl = water gal/bbl for given % CaCl2 (see calcium chloride table in the engineering data chapter, section 4) CaCl2 add = additions of CaCl2 to system volume. CaCl2, lb./bbl = CaCl2 concentration of wt % from the calcium chloride table in the engineering data chapter , section 4
Important Equations Used For Mud Calculations : 1. 2. 3. 4. 5. a.
Volume =[(diameter) 2 * depth] / 1029.415 . Lag Lag stk stkss = volu volume me / POP. POP. Lag Lag tim timee = lag lag stk stkss / SPM SPM . Flow Flow rate rate (GP (GPM)= M)= POP POP * SPM SPM *42 *42 . Flui Fluid d vel veloc ocit ity y (ft (ft / min min)) In pipe : V = 24.51 GPM / d 2 .
b.
In annulus : V = 24.51 GPM / dh 2 – dp2 . OR = POP (bbl/min) / annular volume (bbl/ft) . = ft/min . Crit Critic ical al velo veloci city ty (ft/ (ft/mi min) n) . In pipe :
6. a.
V = [64.57PV + 64.57 { b.
(PV)2 +12.3d2 YP W}] / Wd .
In annulus : V =[64.57 PV + 64.57 {
(PV)2 + 9.26(dh-db)2 YP W}] / W (dh-db) .
7. a.
Slip Slip velo veloci city ty Vs (ft/ (ft/mi min) n) : Laminar flow = [3210(Wc-W) * D 2V2] /339YP(dh-db) + PV V .
b.
Turbu urbule lent nt flow low = 60 {
D(Wc Wc-W -W)) /W /W }
Where : V =fluid velocity (ft/min) . GPM = gallon per minute . d = internal diameter (in) . dh = hole diameter (IN) . dp = pipe diameter (IN) . D = cutting diameter (IN) (IN) (average diameter diameter of sieve) sieve) .
Wc = cutting density (PPG) . L = section length (ft) . W = mud weight (PPG) . Vc = critical velocity (ft/min) . PV = plastic viscosity (cp) . YP = yield point . TVD = total vertical depth . SIDP = shut in drill pipe pressure . KMW = kill mud weight (PPG) . OMW = initial mud weight (PPG) . KRP = kill rate pressure (psi) . F = fanning friction factor dimensionless . Pd = pressure loss . 8. pressu pressure re grad gradien ientt = D * PPG PPG*0. *0.051 0519 9. Density of fresh H2O = 8.33 PPG = 0.433 psi/ft . Density of salt H2O = 8.6 PPG . Density of over saturated H 2O = 8.9 PPG =0.465 psi/ft . 9. Equi Equiva vale lent nt mud mud wt wt : We = Wo + P / 0.0519 * D . We =equivalent mud weight . Wo = actual mud weight . P = surface pressure . D = total vertical depth . 10. Maximum Maximum allowed allowed mud weigh weightt (PPG) (PPG) = leak of pressure(psi) /0.0519 [TVD(ft)*(test [TVD(ft)*(test mud weight) . 11. Kill Kill mud weig weight ht (KMW) (KMW) Mud weight needed to balance a kick = W1 + [SIDP / 0.0519*depth] W1 = initial mud weight (lb./gal) . # Initial circulation circulation pressure pressure (psi) = SIDPP SIDPP + KRP . # Final circulation pressure (psi) (psi) = (KMW (KMW /OMW) * KRP . 12. pressure drop (psi) = [(L*YP [(L*YP / 225*D)] + [PV (L*V) (L*V) / 1500 D 2] L = length of string . V = velocity of mud (ft/sec) D = diameter of hole – OD of drill string (in) YP =yield point . PV = plastic viscosity . 13. Pressure Loss : a. In laminar flow V ≤ Vc . • IN pipe pd =[(PV * LV) LV) / 90,000d2] + YP L / 225 d. • In annulus = (PV * LV) LV) / 60,000(dh-db)2] + YP L / 200(dh-db) . b. In turbulent flow flow V > Vc . • In pipe pd = FLWV 2 / 92880 d . • In annulus = FLWV 2 / 92880 (dh-dp) . 14. Equivalen Equivalentt circula circulation tion density density We = = W + [pd(annulus) / o.o519* L(TVD)] . 15. Reynol Reynolds ds numb number er : a. In dril drilll pipe pipe:: Nr Nr = 15.46 15.46 dvw dvw / PV PV . b. In annulus : Nr Nr = 15.46(dh-db) Vw Vw / PV . Oil Mud Calculations : If you want to raise the percent of diesel from 3% to 8% without reducing the mud weight how many sacks of barite are to be added in order to maintain the same mud weight ? 1. Calculate Calculate how how many bbls of diesel diesel oil oil equivale equivalent nt to 5% differe difference nce to be increa increased sed . EG: System volume = 1,000 bbl . M.wt = 9.5 PPG . X(bbls of diesel) = V(E 2- E1) / 1-E2 = 1,000*(0.08-0.03) / 1-0.08 = 50 / 0.95 = 52 bbls of diesel.
E1 = 3/100 fraction of % of diesel present . E2 = 8/100 fraction of % of diesel required . 2. Adding 52 bbls bbls diesel to system will will reduce reduce the M.wt ,so calculate calculate the new M.wt after after adding 52 bbls of diesel diesel ? V1W1 + V2W2 = (V1 +V2) W3 (1,000*9.5) + (52*7) = (1,000+52) W3 W3 = 9.3943 PPG . V1 = volume of system before adding diesel . W1 = M.wt before adding diesel . V2 = volume of diesel added . W2 = wt of diesel added . W3 = wt reaching after adding diesel . 3. How many many sacks sacks of barite needed to get back back M.wt up to 9.5 PPG PPG ? X = 1490 (W 2-W1) /( 35.5-W2) = 1490(9.5-9.3943) / (35.5-9.5) X = sax / 100 bbl . Total no of sax = (X*1052) / 100 . Oil-Water Ratio : % of oil in liquid phase =[ % oil by volume / (% oil by volume +% H 2O by volume)]*100. % of H2O in liquid phase =[% H 2O by volume(from retort) / (% of H 2O by volume + % of oil by volume)] * 100 EG: M.wt = 18.1 PPG % of oil by volume % from retort = 52 % % of H2O by volume % from retort = 10 % % of solids = 38 % % of oil in liquid phase =[52 /(52+10)]*100 = 84 % . % of H2O in liquid phase = [10 / (10+52)]*100 = 16 %. O/W ratio = 84 / 16 . 1. To increa increase se the the O/W O/W rati ratio o to 90/10 90/10 : O/w =% oil(retort) + X / % H 2O (retort) . 90/10 = (52 + X) / 10 X = 38 bbls diesel / 100 bbl of mud = 0.38 bbl diesel / one bbl of mud Resulting volume = original volume + new volume = 1 bbl + 0.38 = 1.38 bbl 2. To conv conver ertt to one one bbl bbl volu volume me 1 (bbl of mud) / 1.38 (resulting volume) = 0.725 bbl mud . 0.38 (bbl diesel) / 1.38 (resulting volume) = 0.275 bbl diesel needed to be added to the system . I.E: Add 0.275 bbl diesel to every 0.725 bbl mud(of O/W ratio 84/16) to get mud of O/W ratio90/10 . 3. Incr Increa ease se M.wt M.wt up to 18.6 18.6 . (Vm Dm +Vo Do) X + 35 (1-X) = Vf Df . Vm = volume of mud . Dm =density of original mud . Vo = density of oil . Vf = final volume . Df = final density . X = unknown . Let Vf = 1 bbl . [(0.725*18.1) +(0.275*7)]X + 35(1-X) = (1) (18.6) X = 0.822bbls of liquid . 1-X = 0.178 bbls of solids to be added to increase mud weight . EG: Active system Wt = 18.6 PPG . 10 % H2O by retort 48 % oil by retort 42 % solids . 3. On adding adding certain certain volume volume of mud with with a 90/10 90/10 O/w ratio ratio on active active system system and need need to get get O/W ratio ratio 85/15 85/15 for both both and present present mud . The final volume should be 1300 bbls (O/W)1 X + (O/W 2) (1-X) = (O/W 3) Vf Let Vf = one bbl (83/17) X + (90/10) (1-X) = (85/15) (1) 4.882X + 9-9X = 5.667 (1) 4.882X – 9X = 5.667 – 9
4.118X = 3.333 X =0.809 bbl from (83/17) 1-X = 0.191 bbl from (90/10) For1300 bbls the needed volume volume from each mud to be mixed together together to get the (85/15) mud are: 0.809 *1300 = 1052 bbl bbl of 83/17 O/W . o.191 * 1300 = 248 bbl of 90/10 O/W / 1300 bbl of 85/15 of O/W. Begin blending the mud in the active system by transferring 248 bbl of the active system to a reserve pit and add evenly the 248 bbl of 90/10 mud to the active system . The final bbls of new mud mud in the active system is composed composed of ; (0.822) (0.725) = 0.596 bbl mud . (o.822) (0.275) = 0.226 bbl diesel = 0.178 bbl So o.178 (1490) = 265.22 lb. To be added . # To change O/W ratio from 85/15 to 80/20 , water must be added. (% H2O + X) / % oil = O/W then substitute Xo with Vw and Do with Dw in previous equation . Vw =volume of water . Dw = density of H 2O . OR : % of oil to be added: % of H2O by vol. From retort /% of oil (retort) +% of H 2O(retort) + vol. Of oil to be added] = new H 2O by fraction # Needed to cut M.wt 13.3 PPG to 12.3 without affecting volume . vol. = 1425 bbl . fresh mud = 8.4 PPG W1 V1 + W2 V2 = W3 V3 . 13.3(1425- V2) + 8.4 V2 = 1425 *12.3 V2 = 290 bbl . Add 290 bbl on one complete cycle and at the same time dump another 290 bbl of the mud . V3/POP = 1425/0.138 = 10326.086 stk. . Result / SPM = 10326.086 /75 = 138 min . Added vol. / 138 = 2.1 bbl/min .
HYDRAULICS: •
GENERAL HYDRAULICS:
Unit of pressure = psi = pound per in 2. PPG → psi * 0.0519. 3. Weight Weight of 1 gallon gallon of fresh fresh water = 8.33 PPG = 0.433 psi/f psi/ft. t. 4. Weight Weight of 1 gallon gallon of oversat oversaturate urated d water = 8.9 PPG = 0.465 psi/ft psi/ft.. 5. Hydros Hydrostat tatic ic pressu pressure re = Wt(PPG Wt(PPG)) * 0.0519 0.0519 * depth. depth. 3 6. Unit of density = gm/cm . 7. Dens Densit ity y = psi psi/f /ftt * 0.4 0.434. 34. 8. Dens Densit ity y = PPG PPG * 8.3 8.33. 3. 9. Hydros Hydrostat tatic ic head head (psi) (psi) = PPG PPG * 0.05 0.0519 19 * TVD. TVD. 10. Weight Weight of sea water water = 8.5 PPG. 11. Weight Weight of diesel diesel = 7 PPG. 12. Total pressure = hydrostatic pressure + surface pressure. pressure. 13. Pressure gradient: this is the change of hydrostatic pressure with with depth for any given unit of the fluid weight = P/D = 0.0519 * W. 14. Equivalent mud weight: is that that mud weight which the hydrostatic hydrostatic pressure equal to the sum of the imposed pressure and the hydrostatic pressure We = Wo + [ P/ (0.0519 * TVD)]. Where: We = equivalent mud weight. 1. 2.
Wo = actual mud weight. P = surface pressure. 15. Maximum allowed mud weight(PPG): = Leak off pressure (psi) / [0.0519 (TVD + test mud weight). 16. Mud weight needed to balance a kick = W1 + [ SIDP / (0.0519 * depth) ]. W1 = initial mud weight . SIDP = shut in drill pipe pressure. 17. Pressure drop (psi) = {L*YP/225 D}+{PV(L*V)/1500 D2. L = length of string . V = velocity of mud. (ft/sec). D = diameter of hole – OD of drill string (in). YP = yield point. PV = plastic viscosity. v iscosity. 18. Pressure losses: NB: Maximum pressure is at flow line which is after after pumps straight away part of this pressure is lost lost in flow line, another part in drill pipe, another at pit, another part in annulus until it reaches its minimum pressure at flow out line which is zero psi. The summation of this lost pressure is the pressure losses. c. Pres Pressu sure re in lami lamina narr flow: flow: • In pipe (pd) Pd = (PV L V / 90000 d2) + (YP L / 225 d) • In annulus = [PV L V / 60000(dh – dp)2] + [YP L / 200(dh – dp)]. d. Pressu Pressure re loss loss in turbul turbulent ent flow: flow: • In pipe = [FL W V2] / 92880 d2]. • In annulus = [FL W V2] / [92880(dh – dp). Where: V = fluid velocity. d = internal diameter (in) dh = hole diameter dp = pipe diameter. Wo = equivalent M.wt PV = plastic viscosity YP = yield point L = section length. W = mud weight. 19. Effective Circulating Density (ECD): Is that equivalent mud weight for the summation of hydrostatic pressure and pressure loss in the annulus. NB: Pump pressure is affected by : • Diameter of nozzles. • Flow rate. • SPM. • Pump linear diameter BIT HYDRAULICS :
Bit pressure drop ( ∆ P) = [flow(GPM) / {0.95{( π A2+B2+C2)/642 TFA}] * (Mwt/12031). • Hydraulic horse power (energy expended on bit) (BH hP) BH hP = [bit pressure drop * flow rate] / 1714. BHhP/in2 = HhP / π [bit diameter/2]2. To clean out cutting from around bit this method though be used when ∆ P bit = 65% from ∆ Ptotal. • Jet Impact Force(lb.) (force expended by jets in the bottom of the hole). •
(bit ∆ P * M.wt) And result/ (bit diameter/ 2)2 * π . ∆ P bit should be = 48%. OR JIF = (M.wt * GPM * V)/ 1930. • To calculate total flow area of bit (TFA) = [nozzle size / (32/2)]2 = ?. E.g1; [(7/32)2 / 2] = 0.0119628. Area = π r 2 = 3.14 * 0.0119628 = 0.0375. N.B: This is done for all nozzles I.E each one by its own so if three nozzles are of the same size * 3. In our E.g. *3 = 0.1125 E.g 2: We can calculate nozzles size from TFA. Nozzle size for three nozzles = 0.1125 ∴ 0.1125 / 3 = 0.0375 ∴ 0.0375 / 3.14 = 0.01196 – r 2 = 0.0173 * flow rate(GPM) *
r=
0.01196 = 0.1094
D=r*2 = 0.1094 * 2 = 0.2188 D * 32 = 0.2188 * 32 =7
AREA 0F JET NOZZLES (seq. in)
NO
NOZZLE SIZE
AREA OF ONE
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17
7/32 8/32 9/32 10/32 11/32 12/32 13/32 14/32 15/32 16/32 18/32 20/32 22/32 24/32 26/32 28/32 30/32
0.03575 0.0491 0.06213 0.0767 0.0928 0.1104 0.12963 0.1503 0.17257 0.1963 0.2485 0.3068 0.37123 0.4418 0.6013 0.6903 0.7854
44 X FLOW RATE JET VELOCITY = 22 448.8
X 7
•
(A)2+(B)2+(C)2 (64)2
To calculate the neutral point po int : OR in other words the max WOB, so as the maximum WOB will represent 90 % by length of DC weight in mud , so as to keep neutral point within DC. • Max. WOB = length X weight X B.F X 0.9. B.F = Bouncy Factor = 1 – (M.wt /65.4). Weight DC in air = 2.67 X (OD 2 – ID2). 0.9 = 90 % by length of weight DC. NB: The increase of WOB will lead that neutral point will rise rise up, after deciding the length and weight of DC versus maximum WOB to represent 90 % of DC weight (neutral point).
Leak off Test This test is done to determine the maximum pressure the formation can stands, and thus determine the maximum mud weight above which the formation will break down.(NB: differ from one area to another). Leak off test only recommended for exploration wells, not important for production wells. As the maximum mud weight for production areas are already known from exploration we lls drilled before in that area. This is done as follows: • Drill cement, wash pocket and then drill 10 m or 30 ft of new hole, circulate for a few minutes. • Pull to shoe, circulate and condition mud. Make sure that the system is in balance and accurately measure the mud weight, make sure that the hole is filled up. then close the pipe rams. • Pump mud slowly, using the cementing unit until the pressure builds up. measure the volume pumped. Use a calibrated pressure gauge for pressure. • Pump ¼ or 1/8 bbls and wait for one minute or the time required for the pressure to stabilize. • Plot on a graph, the commulative mud volume pumped to the final static pressure. Repeat this for each volume increment. • Continue the procedure until the plotted graph starts to bend off. • Keep well closed to verify that a constant pressure has indeed been obtained. • Bleed off at slow and constant rate, still plotting • volumes and pressures, and establish volume of mud lost in the formation. • Start circulation. Leak off pressure = (PPG). • Maximum allowed M.wt(PPG) = 0.0519X [TVD(ft) X Test M.wt
Pressure (psi)
Pumped volume (bbl)
Pressure Integrity Test This is a pressure test same as leak off test. But in this case we do not need n eed to break formation . I.E: We test the maximum required mud weight we w e are intending to work with following the same steps as leak off test, and when reading this value we stop the test and do not continue until breaking formation. This required mud weight is determined from previous tests in the previous exploratory wells done in this area.
Stuck Pipe A. Ke Key y-S -Sea eati ting ng.. B. Caving. C. Und Under er gau gauge ge ho hole le.. D. Dif Differ ferent ential ial stu stuck. ck. A. Ke Key y-S -Sea eati ting ng:: This usually occurs in deviated holes when the drill pipe wears into the wall of the hole. Since the drill pipe is the smallest diameter in the drill string, the larger diameter tool joints and drill collars can get stuck when making a trip. Key-Seating is recognized by the following characteristics: 1. Stil Stilll havin having g circu circula lati tion on.. 2. Can Can rota rotate te pipe pipe.. 3. May be able able to move move drill drill pipe pipe down. down. Solution: Once the Key-Seating has been formed, the smallest diameter portion of its configuration must be reamed out with some sort of reaming device. B. Ca Cavi ving ng in: Causes: 1. Insu Insuff ffic icie ient nt mud mud weig weight ht.. 2. Wettin Wetting g shales shales causin causing g sloug sloughin hing. g. 3. Insuffici Insufficient ent carryi carrying ng capacity capacity of of the the drillin drilling g fluid. fluid. 4. Tecton Tectonica ically lly stres stressed sed and britt brittle le shales shales.. Caving is recognized by the following characteristics: 1. Can Can not not cir circu cula late te.. 2. Can not move move the pipe(som pipe(sometime etimess the pipe pipe can be moved moved down words but not up. up. 3. Can Can not not rota rotate te the the pip pipe. e. Solution: 1. Increase Increase mud weight weight to to balance balance formation formation pressur pressuree if possible possible.. 2. Use drilling drilling fluid fluid that will will not wet or hydrate hydrate the shales shales and at the same time time stabilize stabilize shales shales such as KclKclPolymer Mud. 3. Increase Increase the carry carrying ing capacity capacity of the the drilling drilling fluid fluid by increas increasing ing YP. C. Und Under er gau gauge ge ho hole le:: Causes: 1. Under Under gaug gaugee dril drillin ling g assem assembly bly.. 2. Plastic Plastic following following formations formations(such (such as salt or soft soft formations) formations) caused caused by overburden pressure pressures. s. 3. Flocculated Flocculated mud mud and aggregat aggregated ed mud causes thick filter filter cake. cake. 4. Wall cake build build upon a porous porous formati formation on in an already already gauge hole. 5. All of these these can be complicated complicated by additions additions of drilled drilled solids solids to the drillin drilling g assembly, assembly, commonly commonly refereed refereed as (Bit Balling). Solution: 1. Check Check the gaug gaugee of the the drilli drilling ng assemb assembly ly.. 2. Increase Increase mud mud weight weight to to control control formation formation pressures. pressures. 3. Reduce Reduce filtr filtrati ation on to form form a smaller smaller wall wall cake. cake. 4. Reduc Reducee bit bit balli balling ng by : • Change to inhibitive mud. • Add surfactants (detergent). • Slugs (having nut plug + caustic soda + spersene). • Redicoat. NB: When bit is balled, getting high torque, no progress. D. Dif Differ ferent ential ial Stic Stickin king: g:
Differential sticking is defined as the sticking of pipe at one side of hole against a permeable formation because the drilling fluid pressure exceeds the pore fluid pressure of the formation, which causes break of the formation, which by turn will cause a complete c omplete loss. And thus the tendency of sucking of drill string to any side of pore hole is possible. Differential sticking may occur in any area of drilling but mostly occurs where deep wells are drilled with high density mud. Differential sticking is characterized by: 1. Drill Drill with with lowes lowestt mud weig weight ht pract practica ical. l. 2. Mainta Maintain in low filtra filtrati tion on rate rate.. 3. Use Use lubr lubric ican antt. 4. Do not allow allow the pipe to remain remain motionless motionless for any period period of time. time. 5. Use square, square, hexagonal hexagonal,, or spherical spherical drill drill collars. collars. 6. Chan Change ge to to INVE INVERM RMUL UL.. 7. USE a spot spottin ting g fluid fluid (ENVI (ENVIRORO-SPO SPOT). T).
ENVIRO-SPOT spotting fluid formation for 100 bbls
WEIGHT (PPG)
7 .3
10
12
14
16
18
OIL (BBL)
65
58
54
49
51
44
ENVIRO-SPOT 55 gal Drum
6
6
6
6
6
6
WATER (BBL)
28
26
22
21
11
10
BARITE 100 lb. bag
_
140
250
350
465
570
Start with required volume of oil, add ENVIRO-SPOT, wa ter and barite in that order
DRILL PIPE CORROSION Corrosion is the destruction of metal by chemical o r electrochemical action between the metal and a nd its environment. I.E: Corrosion occurs as a result of interaction between iron steel of drill string string and water base mud. Four conditions must be met ,however , before wet corrosion: 1. Anode and cathode must exist. 2. The anode and cathode must be immersed in electrolytic medium. 3. A potential difference between anode and cathode exists. 4. There must be a coupling to complete the electrical circuit. • The anode and cathode exist on the drill pipe itself. e lectrolytic medium. • The drilling mud may serve as electrolytic • The coupling is creating by the drill pipe steel . • The potential difference is due to the crystalline structure and different metal used in the drilling pipe alloy.
Factors affecting corrosion rate: 1. Oxygen: Oxygen reacts with metal of drill string forming (Fe2O3 & Fe3O4), which accelerates corrosion on metal. Oxygen acts to remove protective films on drill d rill string which accelerate corrosion action and increase pitting deposits ( reddish brown rust of Fe(OH)3 . Oxygen scavengers, passivating inhibitors and filming inhibitor treatments are used to mitigate oxygen corrosion attack. 2. H2S: Fe + H2S FeS + 2H+ . The increase of H+ atoms in mud will result in retaining acidic medium which will increase corrosion effect. H2S, cause severe pitting embattlement and stress cracking also a black sulfide coating. • Treat with sulfide scavenger as ZnO. Also F ilm-forming inhibitors are used. • Keep pH between 8-9. 3. CO2: CO2 is an acidic gas that results in pH reduction and thus increases corrosion corrosion effect and pitting attack. CO2 + + H2O H2CO3 (Carbonic acid). H2CO3 + Fe FeCO3 +H2. I.E: FeCO3 deposits indicate CO2 attack. • Increase M.wt to stop gas influx . • Keep pH between 8-9. • Add filming amine 4. Bacteria: • the by-product of bacteria is CO2, H2S and SO4(leads to H2SO4). • Microiobacids are use to control bacterial effect in drilling en vironments. 5. Dissolved Salt: As salt concentration increases, conductivity between charge poles raises, also electrical resistance of drilling fluid decreases . also increase the solubility of corrosive by-products and thus increase corrosion effect. 6. Velocity of Drilling Fluid: the higher the mud velocity the higher the rate of erosion of films around the drill string and thus the higher the rate of corrosion (Treat with oil mud , amines). 7. Temperature: Rule of thumb : Corrosive rate doubles with every 55 ft increase. As the increase of temperature increases the solubility of corrosive gases(O2, H2S & CO2).
8. Pressure: the increase of pressure causes an increase in trapping effect of gases in mud such as O2 and thus causes increase in corrosion effect. 9. pH: Corrosive is much slower in alkaline medium than in acidic medium. So corrosive rate decreases as pH increases. NB: The best medium of pH to minimize corrosion rate is a pH between 8.5-10. 10. Solids: Increase of abrasive solids in mud accelerates removal of protective film around drill string due to increase of friction action causing pipe washout. Also removal of protective film helps corrosive elements attack to drill string steel and thus accelerate corrosion rate. See pages 7, 8, 9