SPE 120265 Analogous Reservoirs to Chicontepec, Alternatives of Exploitation for this Mexican Oil Field Heron Gachuz-Muro, SPE/Pemex E&P; Hedi Sellami, SPE/ENSMP
Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 2009 SPE EUROPEC/EAGE Annual Conference and Exhibition held in Amsterdam, The Netherlands, 8–11 June 2009. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract The giant Chicontepec field contains oil from 18 to 45 oAPI in laminated sandstones of 0.1 to 10 mD at a depth of around 2500 meters (8202 ft). Original Oil in Place (OOIP) is estimated to be 140, 900 MMSTB. The complex geology (complicated structural and stratigraphic nature of the reservoirs), lack o f reservoir information and lack of technology availability caused a gap between discovery and development. Throughout a period of several decades some exploration wells were drilled based on 2D seismic and log correlations of the reservoirs. The exploitation of the Paleonchannel was postponed because most of the wells showed poor productivity. The reasons for the low recovery (around 3%) have never been thoroughly understood. Various hypotheses have been proposed to explain the deficient performance such as partial closing of the fractures with declining reservoir pressure (bubble-point pressure is near initial pressure), inadequate comprehension of the geological model, deficiency in the fracturing technology, oil-wetted or intermediate-wetted reservoirs, applicability of unconventional wells (horizontal wells, casing drilling technology), etc. Today, the Chicontepec Paleochannel is an intermediate stage. Due to the experience of different fields with similar characteristics, this paper describes an analysis of alternatives that may be considered to resolve the problems of exploitation at the Chicontepec field. Advanced technologies, hydraulic fractures, artificial lift systems, all of them combined with secondary and enhanced oil recovery, may be feasible to sustain or increase production. A number of hurdles will have to be overcome. This field, the second most important oil field in Mexico, should take advantage of the experience learned from these analogous reservoirs.
Chicontepec Paleochannel Geographically, it is located in east-central Mexico in parts of the states of Veracruz, Puebla and Hidalgo. Chincontepec system was deposited under complex tectono-stratigraphic conditions. Geologically, it covers an area of 957,534 acres (Figure 1). Aproximately half of Chicontepec consists of shales or silty shales with the rest of the formation made up of multiple thin sandstones beds and zones of sandstones beds. Typically, between 8 and 16 major reservoirs are present. These set of reservoirs is composed of channel complexes that are flanked by, and rest on, lobe sandstones that grade into distal fan and basin floor deposits, resulting in high heterogeneity. Throughout a period of several decades so me exploration wells were drilled based on 2D seismic and log correlations of the reservoirs. The 3D seismic allowed the identification of sand bodies with viable pay thickness. Some wells produce small amounts of water, in general, water-oil contacts have not been identified. X-ray diffraction analysis showed that the clay cointains dominantly kaolinite with a content of 1 to 5 %. The sandstones are immature litharenites consisting of quartz grains, abundant carbonate fragments, and granitic fragments. Because of the abundance of carbonate in the system, the sediments are highly cemented by ferroan calcite and ferroan dolomite, in addition to quartz overgrowths. Core analyses show that the reservoirs are characterized by both low porosity and low permeability, Figure 2. All the reservoirs have permeabilities of 0.1 to 10 mD and porosities ranging from 5 to 15 %. The effective permeability, as determined from build up, fall off, drawdown and step rate test or advance decline analysis, varies from 0.01 to 15 mD.
Figure 1.- Location of the Chicontepec Paleochannel.
Figure 2.- Porosity versus permeability from core analyses.
Chicontepec was organized into 8 sections or areas w ith 29 fields of which two sectors are being exploited, Figure 3. There is no physical activity in the rest of the areas; nevertheless, there is sufficient potential for a future development. Chicontepec was placed on production in 1952. The exploitation of the Paleonchannel was postponed because most of the wells showed poor productivity. The reasons for the low recovery have never been thoroughly understood. Until 2007, 1313 development wells had been drilled. Peak production was of 33 Mbls in 2008. The oil density varies from 18 to 45 oAPI depending on its structural position (at a depth of around 8202 ft). A formation volume factor of 1.20 RB/STB and a gas/oil ratio of 63.8 m3 /m3 at original reservoir conditions (3228 lb/pg 2 and 167 oF, approximately) are representative values of theses reservoirs. Primary recovery by solution gas drive is less than 5 porcent of oil in place. Analyses of cores and microseismic monitoring tests showed a NE-SW fracture orientation.
Figure 3.- Chicontepec sections.
Many wells are being exploited with massive hydraulic fracturing, together with artifical lift systems. Some wells have been directionally drilled from central locations to minimize environmental impact and produce into centralized facilities. A variety of different fracturing designs have been used through of the years. Some multiple reservoirs were fractured within the same wellbore, stagged fractures were achieved. During all these years, a diversity of fluids, proppants and pumping schedules were used to balance the operational and theoretical design considerations, however, implementation of these technologies have not resulted in maintaining or raising the oil rates. Partial closing of the fractures with declining reservoir pressure is believed to be a cause of such low oil production rates. A short-term pilot injection test was carried out in a selected area of two reservoirs from the Chicontepec Paleochannel. The pilot water injection area was basically an incomplete inverted seven-spot pattern. The pilot was located in an upward fining and blocky channel deposits. For the pilot area was observed that sand continuity and reservoir rock quality are good in a northern direction from the injector, decreasing in east and southeast directions, which has a good similarity from the tracer response. The results seem to indicate that numerous reservoirs could benefit from a long-term water injection program. Some analogous fields worldwide will be reviewed. The aim is to cover the most important remarks. In addition, the major solutions took into account to increase, enhance or sustain the oil production will be mentioned. Multiple techniques and technologies applied or used to understand the behavior of the reservoirs will be analyzed below. In both cases studied, theses lessons may make feasible production in the second most important oil field in Mexico. The successes and failures can provide vital examples into how to best manage Mexican oil fields.
The Pembina Cardium field was discovered in 1953 and it is located in the Province of Alberta, Figure 4. The reservoir is a stratigraphic trap. The pay zone comprises two sand members. The upper sand (the most important reservoir) is a finegrained, well-sorted, quartzose sandstone. The lower sand consists of numerous shales and sand lenses. Waterflooding has been the main recovery method since 1960. In most production wells, a steady decline is seen in both oil and total fluid rates. The natural recovery mechanism is by solution gas drive. Formation damage is a probable cause for such behaviours. The main portion of the reservoir was developed on 80-acre spacing and the flank areas on 160-acre spacing. The saturation pressure varies from 1,443 to 2,666 psi and gravities ranges over several degrees, 37 oAPI the average. The initial pressure was 2,715 psi (Pembina #1). The initial production oil rate (Pembina #1) was around 76 bopd, however, after fracturing the oil rate increased to 281 bopd. After that, every well had to be fractured to obtain commercial production.
The Pembina “E” Lease is representative of the large portion of the Permina Cardium field, characterized by a low productivity. This Lease began its development in 1954. 36 wells were drilled on 160-acre spacing. The wells were produced by hydraulic fracturing. Peak production was of 2,610 bopd (January, 1957). After, the minimum was reached just prior to the start of gas injection. Pembina “E” Lease produced by gas injection approximately 1,200 bopd (stabilized production). 2% of the OOIP had been recovered before to get to the bubble-point pressure. Original reservoir pressure and temperature were found to be 2690 psi and 126 oF, respectively. Under primary recovery, the wells in Pembina exhibited a gas-oil ratio performance abnormal in most oil reservoirs. Carter and al. (1960) showed that high gas saturation had developed in the neighborhood of the wellbore as a result of the drawdown (differential depletion). This event became a critical factor. For this reason, a secondary recovery was considered (water or gas injection). The evaluation pointed out that the water injection rates would be too low for economical considerations; however, good injectivity could be obtained by using gas. The gas injection program was instituted in the low capacity areas of the field (< 100 md.ft) when the reservoir arrived at the bubble point pressure. Table 1 summarizes the reservoir and fluid characteristics. Key Parameters: • • • •
160-acre well spacing scheme preserved. Gas supply came from a processing plant (2 miles of distance). Gas injection implemented. Hydraulic fracturing.
Table 1.- The reservoir and fluid characteristics. Area (acres) 5760 Well Spacing (acres) 160 Depth (ft) 5650 Net Pay (ft) 16 Porosity (%) 15.5 Permeability (mD) 6.6 Sw (%) 11 o Temperature @ 2300 ft ( F) 126 Oil viscosity @ Pb (cp) 0.8 Original Pressure @ 2300 ft (psi) 2690 Bubble Point Pressure (psi) 2457 3 GOR (ft /bl) Bo (RB/STB) 1.37 OOIP (MMbls) 72
Figure 4.- Pembina Cardium Formation.
The Garrington Cardium field is located next to Calgary. This field has two pools, Cardium A and Cardium B. It was discovered in 1954 and a program of water injection began in 1965. The field has four Units. Cardium A is related to the sand of Pembina field. However, it is thinner, well shorted, fine-grained, and clean sand. The Sand A has both a reduced porosity and permeability. It is composed generally of quartz and chert grains with minor amounts of feldspar, mica, and unusual glauconite. The dominant clay minerals are illite, chlorite and kaolinite, with vestiges of montmorillionite. The kaolinite could be of diagenetic origin. Sand B is different in mineralogy, grain sizes ranges from fine sand to gravel, and coarse to very coarse sand is common. This sand was made of quatz, chert, quartzite, and rock fragments. Clay mineralogy is like Sand A. In general, Sand B has better reservoir properties. The injection of water began in 1965 (Garrington Unit 2). It was used a nine-spot pattern. It was calculated a total sweep efficiencies of 5.38 % for Cardium A and 18.38 % for Cardium B. An oil rate production from 670 bopd was reached in 1968. Six years later, production declined. A workover program increased the Unit production. In 1976, approximately 20 % of the OOIP was obtained (12.14 % by primary recovery). Table 2 concentrates the basic properties for both Cardium sands. During the waterflood operations, by plugging problems of the formations because of movement and accumulation of fines were detected. Since 1975, several surfactant treatments were conducted to restore productivities.
Table 2.- The reservoir properties. Well Spacing (acres) Depth (ft) Net Pay (ft) Porosity (%) Permeability (mD) Oil viscosity @ Ps (cp) Oil gravity (API) Swi (%) o Temperature ( F) Original Pressure (psi) Bubble Point Pressure (psi) Bo (RB/STB) OOIP (MMbls)
6,500 2.12 12.05 6.99
6,700 3.06 13.31 43.23
0.530 39 11.4
142 3,400 2,221 1.348
• • • •
Surfactant treatments were used for re-establishing productivities. The formations were found oil-wet. Serious producing problems were encountered using completion completion wells with 3 ½” or 2 7/8”. Conventional wells with 4 ½” casing were recommended.
The Wertz field is located in the Great Divide Basin (Wyoming), Figure 5. The field produces from the Tensleep sandstone and Madison carbonate. The reservoir was discovered in 1936. Primary production is a combination of water influx and fluid expansion. The Tensleep sandstone occurs at an average reservoir depth of 6,200 ft with a net thickness of 236 ft. Permeability is low at 13 mD and a porosity average 9.9%. The reservoir fluid is an undersaturated black oil (35 oAPI). A CO2 injection program (WAG) began in Wertz Tensleep in October, 1986. Before that, a pressurization phase was instituted to return the reservoir to its initial pressure (injection of water). During the CO 2 injection, some producing wells were equipped with electric submersible pumps. The production peaked at an oil rate production of 11,700 bpd. Since the start of the gas injection, an infill program was implemented to develop down-structure acreage and reduce spacing in large interior patterns.
Key Parameters • • • • • • • •
Waterflood response was extraordinary. Reservoir pressurization. Miscible displacement. Additional drilling. High injectivity. Vertical and areal sweep efficiencies were encouraging. Nominal 10-acre well spacing. Minimal operational problems (asphaltene precipitation, some evidence of corrosion, etc).
The Long Beach Unit (LBU) of the East Wilmington field is a turbidite formation consisting of low permeability (2-50 mD). The LBU has been under injection of water since 1965. The Unit is very mature (Tar, Ranger, Terminal, U-P Ford zones) and its production is declining. The Union Pacific Ford zone (U-P Ford zone) has the poorest reservoir quality. We will present and analize to the Union Pacific Ford zone. The depth of the zone ranges from 4200 to 4800 ft. The gross thickness both U-P and Ford are 900 and 1200 ft, respectively. Some sandstones reveals a coarsening character, some more reveal a blocky or fining character. In general, the U-P Ford sandstones are lithic arkoses composed of quartz, plagioclase, potassium feldspar, mica and rock fragments. The clays (10-20 %) can damage the reservoir due to swelling, fines migration and the formation of precipitates from acidizing. The heterogeneous nature combined with a peripheral waterflood, conducted to poor recoveries in the period from 1970’s to 1980’s. In 1992, a new design was proposed with both pattern injection and hydraulic fracturing. Tree years later, a 3D seismic survey was achieved to understand better the reservoirs, however, the seismic modeling didn’t offer adequate support to determine the fluids migration, it only helped to clarify the geometries of faults and indicate sand bodies. The U-P Ford reached a peak rate of about 30,000 bopd, after the oil rate declined. Over the past 20 years, the production rates have fluctuated from 4,000 to 3,000 bopd. Many different techniques have been applied to impact on well productivity for instance: 1) better drilling methods, 2) better workover fluids, 3) cleaner injection water, 4) good hydraulic fracturing, and 5) sand control. Horizontal drilling was not successful due to the heterogeneity of the formation but it is still are being evaluated as an option.
Key Parameters • • • • • •
Potassium chloride (KCL) is used to reduce formation damage during workover operations Two completion types (cased-hole and slotted liner completions) are used depending on the geology. Changes in frac job parameters including frac-and-pack techniques. Electrical submersible and progressive cavity pumps were used. Water injection using pattern schemes. Some old wells were either refractured or reperforated with new strategies.
Figure 5.- Wertz field location.
The Priobskoye field was discovered in 1982 and it is located in the Central part of West Siberia. The field was divided into 2 sections. The southern area has one reservoir of 3 to 20 mD and 3 reservoirs (0.1 to 10 mD) separated by shales. The field ranges between 7870 and 8530 ft of depth with average porosity 18 % and high oil saturations, from 50 to 56 %. The reservoirs have neither free mobile water nor aquifer support. The oil production rates declined quickly without any support. This section (southern area) is under injection water. The original pressure was about 3760 psi with a saturation pressure 1170 psi. The reservoir fluid has low viscosity and low gas-oil ratio. A pilot program was evaluated to contribute to the production optimization (massive hydraulic fracturing accompanied with artificial lift systems). This program demonstrated that it was possible to raise the oil production. It was reached a peak production about 200,000 bopd using massive hydraulic fracturing, ESP pumps, commingled production and selective water injection.
Key Parameters • • • • • •
Massive hydraulic fracturing, ESP pumps, commingled production and selective water injection. Continuous monitoring. 7 spot patterns using a 1640 ft (500 m) well spacing scheme. The direction of maximum stress was assumed to be 45 0 NW. 3D seismic. ESP´s flowing with bottom-hole pressure below the buble point pressure.
The Malobalykskoe field is situated in Siberia and is mainly represented by alternating sandstones, siltstones and argillites. The field has between 8 and 23 permeable layers (BS16-22 formation). In general, a permeability of 2 mD is found around this formation with an initial pressure of 4032 psi. The BS16-22 is considered uneconomical without hydraulic fracturing. There were obtained positive effects on recovery factors using massive fracturing.
Key Parameters •
Fracture designs were adapted to the mechanical conditions of wells and to the reservoir properties.
Kalchinskoye was discovered in 1990. The field is situated in the vicinity of Tyumen, Siberia. The Cretaceous sands were regarded as the more productive (this area includes lower Cretaceous and middle Jurasic sands) occurring at depths of 8200 to 9030 ft. The main characteristics are described in table 3. The Achimovskoye formation covers approximately 12,602 acres with average net pay of 109 ft. The sands are arkosic litharenites consisting of fine grained. Core analyses identify porosities normally average 18 % and the effective permeabilities fluctuate in the range of 5 to 10 mD. The oil is being produced with artificial lift systems such as sucker rod and submersible pumps.
Table 3.- The reservoir parameters. Porosity (%) Permeability (mD) Average net pay (ft) o Oil gravity ( API) Viscosity (cp) Original pressure (psi) o Temperature ( F) Average production (bopd/well)
18 5-10 33 27.5 2 3234 181 245
Key Parameters • • •
Production with artificial lift systems (sucker rod and submersible pumps). Water injection. Fracturing using both borate crosslinked water and gelled diesel systems.
The Sirte basin in Libya was subdivided into different exploitation areas, see Figure 6. Since 1970, so me fields with potential reservoirs were detected. The Sarir sandstones consist of two layers Upper and Lower Sarir sandstones. These reservoirs are stratified with medium to very low permeability (low to moderate production) but the oil properties are very favourable. Both active aquifer and underlying aquifer were observed into the fields. All fields are at depths from 10,000 to 14,000 ft. The primary recoveries are low because of the poor reservoir rock properties. The main parameters are summarized below, see table 4. The matrix rock is considered with intermediate wettability. The oil production is reached after hydraulic fracturing. This kind of technology has shown to be a succesfull instrument for the reservoir management. Due to low vertical permeabilities, horizontal or multilaterals wells were not considered competitive with the reservoir conditions. In general, the Saris Sandstones were identified as Improved Oil Recovery (IOR) and Enhanced Oil Recovery (EOR) opportunities.
Table 4.- The reservoir parameters. Porosity (%) Permeability (mD) Net pay (ft) Swi (%) Depth (ft) o Oil gravity ( API) Viscosity (cp) Original pressure (psi) o Temperature ( F) Average Bo (RB/STB) Average production (bopd) Dykstra-Parson coefficient
Key Parameters • •
3D seismic. Fracture lengths comfirmed by well tests.
Figure 6.- Sirte Basin in Libia, exploitation areas.
Opportunities Opportunities of Development Mexico is one of the main oil producing countries in the world. Today in the country, there are not many projects related to EOR processes. For instance, Cantarell field (the main oil field) has good success with nitrogen injection, both KMZ and J-T fields started nitrogen injection, T-C field evaluated a tertiary program with CO 2, C field operators opted to use air injection while CH field is being evaluated to inject dry gas, etc. Undoubtedly, both decline and high oil prices have stimulated the development of EOR opportunities. As we have seen, due to the experience of the different fields described, Chicontepec could take advantage of significant opportunities. Hydraulic fractures, artificial lift systems, all of them combined with secondary and enhanced oil recovery, may be feasible to sustain or increase production. In general, four factors were identified which will have a direct impact into the oil production: 1) hydraulic fracturing optimization, 2) artificial lift systems, 3) water or gas injection, 4) New wells.
Artificial Lift Systems.- These days, some wells in Chicontepec make use of pump-jack unit and lift systems. Many oil wells are in danger of being shut-in due to low productivity index. As mentioned, Electric Submersible Pump (ESP) systems are the dominant method for producing oil in Russia. Chicontepec could benefit with progressive cavity pump and ESP systems. Hydraulic Fracturing.- A variety of different fracturing designs have been used through the last years. During all these years, a diversity of fluids, proppants and pumping schedules have been employed to balance the operational and theoretical design considerations. Recently in Mexico, several tests were successful with fluids that contain CO 2. The use of liquid CO 2 as a fracturing fluid offers a viable method of stimulation. It would be recomended to monitor the fractures using microseismic events detection or permanent sensors. Conventional and Unconventional Wells.- Many of the wells have been directionally drilled from central locations. Although the results have been uncertain, horizontal and multilateral wells are still being evaluated as a way to produce selected reservoirs. Additionally, it will be important to reduce the damage to the formation by long operational times during workover, completions and drilling practices.
EOR Processes.- Since 2004, De Swaan obtained good recovery factors using water injection (simulation model). Due to the heterogeneity in the Chicontepec Paleochannel, some reservoirs should be programmed with water injection using reservoir rock quality and fracture orientation. In addition, surfactant flooding processes could be considered as well. Selective waterflood would the best option due to the high heterogeneity.
EOR technologies have demonstrated around of the world to be profitable in commercial scale applications. These processes would provide an extra value added with additional oil rates. Meza (2004) pointed out that the injection with CO 2 is considered as a potential method in the Chicontepec fields. Carbon dioxide supply can be obtained of natural or industrial origin. The Chicontepec Paleochannel could use CO 2 produced from a natural source. Figure 7 provides the location of the natural reserve. Thirty porcent of the CO 2 will be sent to the local fields and the rest would be available. The use of CO 2 may be contemplated for either a miscible or an immiscible project. CO 2 injection is the process which can be applied in a variety of schemes such as Cyclic Steam Stimulation (Huff ‘n’ Puff), Water Alternated Gas injection (WAG processes can be grouped in many ways), Continuous Injection, Fracturing, etc. There were one hundred CO 2 projects under miscibility conditions in the United States. Figure 8 shows the increase in the number of active projects. In general, CO 2 would be an economical alternative in reservoirs with complex geology.
Hydraulic fracturing, artificial lift systems and selective water (or gas) injection would contribute to the production optimization.
Proper candidate evaluation, equipment selection, installation procedures and root cause of failure analyses applied in Chicontepec will improve the fruitful life in some wells.
The lessons learned in other fields can be applied to commercially develop the rest of the areas of this giant reservoir.
Optimal drainage radius could be calculated using correlation for the turbidites reservoirs.
T-C Field 18 oAPI
B o B A rc a o ó d n a r a C e D a T t e r pi c T pi m a c o Ma Ma - e t n
m a m A L A m o L l R d l e d s a R l l a e
. DE L CH AMP AY AN
L. JOS E E TO SI TO
. A P L LA UE NTE
L.D E E CH CH AM PAYAN
L. TO QUI L QUI LA LA
. DE L CH AMP AY AN L. LAS P NT I AS
L.D E E Q UI NT Q NT ERO
. DE L CH AMP AY AN
O T I R AM ES I
.J OP L .J OP Y O
Al am t am ira ir a S I V A UE N N A . B L
.D E CH L .D E CH AMP YAN YAN A
Candidate Fields 22-30 oAPI
O LAGU NA LA RTU GA O T GA
L A G UNA
ISAL SL A L ATO L RT RUGA T
V E G A E S CO ND D IA
RIO L A G UNA DE L CHA I REL
TA ME S I
AUNAD L AG G EC HI LA AG A L G UNA D E C E HI LA C LA
O U C N A N O P A R I
L A G U N A
ACA N ACATA ACA N TA TA
D EPU EB L O V EJO I
ERR O L C O L A PE Z
AG L AG A L AG UNA UNACER UNA G CER CER RO R RO O
LA S I MA LAN R D MA LAN D R D
APE L APE A L PE Z Z
LA LA GNA GU GU NAS U S EC EC A A
.DETA L DETA NC HI CU IN
. DE L LAS OL OLAS
GUN A L GUN G A L GUN UN ACHA A CHAJ CHA L I J L I J
E S T ER O D E T A MA C U L I
G A L
A N U
A U G I
M ES ES ERO T ERO T
OP T OP T LA I LA I
L. EL TULE
O C U N A P I O R
L. A L MILL A
L NAHUA . TLAN
Candidate Fields 08-11 oAPI
N A A Y C CH I R IO
X ISAFR SL A L FR ONTO ONTO N
ISLA SLA JUANA. RAMIREZ ISLAP EREZ EREZ
I ISLA BURROS
Candidate Fields 27-32 oAPI
Figure 7.- Natural CO 2 source for the Chicontepec fields.
Projects in 2008 USA 120 100 CO2 Miscible Miscible
Acknowledgements The authors would like to thank Pemex for permission to publish the analyses included in this paper. Thanks to Michel Tijani, without his help, this research would have not been possible.
Nomenclature 2D 3D Bo cp EOR ESP GOR IOR mD Np OOIP Pb K Sw
= = = = = = = = = = = = = =
two dimensions tree dimensions formation volume factor, RB/STB centipoise Enhanced Oil Recovery Electric Submersible Pump gas/oil ratio, ft3 /bl Improved Oil Recovery miliDarcies cumulative oil production, Bls original oil in place, Bls buble point pressure, psi permeability, miliDarcies water saturation, porcent
Beuthan, H. C.; Shibani, M. 2006. Business Improvement by Integrated Concession Development. Paper SPE 99703, presented at the 2006 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 12-15 June.
Berumen, Sergio; Kaiser, Penelope; Gachuz, Heron. 2004. Fracturing Microseismic Response in Turbidite Reservoirs in Tajin Field. Paper SPE 92015, presented at the 2004 SPE International Petroleum Conference, Puebla, Mexico, 8-9 November.
Berumen, S.; Gachuz, H.; Rodríguez, J. M. 2004. Hidraulic Fracture Mapping in Treated Well. Channelized Reservoirs Development Optimization in Mexico. Paper Z-99, presented at the EAGE 66 th Conference and Exhibition, Paris, France, 7-10 June.
Bondor, P.L.; Hite, J.R. 2005. Planning EOR Projects in Offshore Oil Fields. Paper SPE 94637, presented at the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, Brazil, 20-23 June.
Borling, D.; Sviderskiy, S. 2008. “Pumping up the Life” of Electric Submersible Pump Systems, Russian Federation. Paper SPE 116905, presented at the 2008 Oil and Gas Technical Conference and Exhibition, Moscow, Russia, 28-30 October.
Busch, D.A. and Govela, A. 1978. Stratigraphy and Structure of Chicontepec Turbidites, Southeastern TampicoMisantla Basin, Mexico. American Association of Petroleum Geologists Geologists Bulletin, v.62, No. 2, 235-246.
Chakravorty, S. K.; Brown, P. R. 1978. A Review of Waterflood Performance in Garrington Cardium A and B Pools, Unit No. 2. JPT (Paper SPE), June, 869-876.
Comesa/PEP. 2007. Reingeniería para el Campo San Ramón, para el Proyecto Aceite Terciario del Golfo y para los Campos del Activo Bellote-Jujo. Pemex E&P, Internal Report.
10. Comesa/PEP. 2006. Análisis de Caracterización Dinámica, Ingeniería de Yacimientos y Simulación de Yacimientos para los Campos de la Región Norte. Pemex E &P, Internal Report. 11. Comesa/PEP. 2005. Evaluación, Desarrollo e Implementación de los Programas de Recuperación Secundaria y Mejorada para los Campos de la Región Norte. Pemex E&P, Internal Report. 12. Comesa/PEP. 2004. Reingeniería de los Proyectos de Inyección de Agua y Diseño de los Nuevos Proyectos de Recuperación Secundaria y Mejorada en la Región Norte. Pemex E&P, Internal Report. 13. Comesa/PEP. 2003. Actualización del Modelo Geológico e Ingeniería de Yacimientos, Campo Soledad-Soledad Norte Pemex E&P, Internal Report. 14. Comesa/PEP. 2002. Caracterización Estática-Dinámica, Ingeniería de Pozos-Yacimientos, y Simulación Numérica de Yacimientos, Campo Coyotes. Pemex E&P, Internal Report. 15. Createch/PEP. 2003. Microseismic Monitoring in Chicontepec. Internal Report. 16. Davies and Associates. 1996. Formation damage study, Agua Fria-801, Agua Fria-836 and Antares-1 Wells, Agua Fria Field, Chicontepec Basin, Mexico. U npublished Report. 17. Droegemueller, U.; Leonhardt, B. 2005. Hydraulic Frac Stimulations in a Libyan Oil Field – A Case History. Paper SPE 95019, presented at the 2005 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 25-27 May. 18. Gachuz-Muro, H. 2009. Effective Permeability vs Drainage Radius, Correlation for the Turbidites Oil Reservoirs.Chicontepec Paleochannel. Paper SPE 120267, presented at the 2009 SPE Middle East Oil & Gas Show and Conference, Kingdom ofBahrain, 15-18 March.
19. Gachuz-Muro, H.; Berumen-Campos, S. 2007. Quebrache, a Natural CO 2 Reservoir: a New Source for EOR Projects in Mexico. Paper SPE 107445, presented at the 2007 SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, Argentine, 15-17 April. 20. Moritis, G. 2008. More US EOR Projects Start but EOR Production Continues Decline. Oil and Gas Journal, 21 April. 21. International Symposium on Improved Oil Recovery, Tripoli, Libya, 16-18 September. 22. Jenkins, C.; Al-Sharif, S. 2004. Forty Years of Improved Oil Recovery: Lessons From Low-Permeability Turbidites of the East Wilmington Field, California. Paper SPE 92036, presented at the 2004 SPE International Petroleum Conference, Puebla, Mexico, 8-9 November. 23. Japan National Oil Corporation (JNOC), Technology Research Center and PEMEX Exploración y Producción. 2001. Geostatistical Modeling of Chicontepec Reservoir: Agua Fria, Coapechaca and Tajin Areas. Unpublished report. 24. Justen, J. 1957. Canada’s Pembina Field. JPT (Paper SPE 856), September, 21-26. 25. King, R. W.; Adegbesan, K. O. 1997. Resolution of the Principal Formation Damage Mechanisms Causing Injectivity and Productivity Impairment in the Pembina Cardium Reservoir. Paper SPE 38870, presented at the 1997 Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October. 26. Kleinstelber, S. 1990. The Wertz Tensleep CO 2 Flood: Design and Initial Performance. JPT (Paper SPE 18067), May, 630-636. 27. Kloepfer, C. V.; Tracy, G. W. 1961. Gas Injection Performance of the Pembina “E” Lease. Paper SPE 172, presented at the 36th Annual Fall Meeting of the SPE of AIME, Dallas, texas, 8-11 October. 28. Kondratoff, L. B.; Khasanov, R. N. 1998. Hydraulic Fracturing Provides Production Gains in Kalchinskoye Oilfield of Western Siberia. Paper 39954, presented at the 1998 SPE Mountain Regional/Low Permeability Reservoirs Symposium and Exhibition, Denver, Colorado, 5-8 April. 29. Kryuchkova, T; Igoshkin, V. 2006. Production of Turbidite Reservoirs in Russia- A Pilot Field Development Case Study. Paper SPE 103987, presented at the First International Oil Conference and Exhibition in Mexico, Cancun, Mexico, 31 August- 2 September. 30. Last, G. J.; Craig, F. F. 1964. Significance of Partial Pressure Maintenance by Fluid Injection. JPT (Paper SPE 669), January, 20-24. 31. Leonhardt, B. 2003. Hydraulic Frac Stimulation of the Sarir Sandstone in Nakhla Oilfield. Paper presented at the Second 32. Lowry, P.; Jenkins, C. 1993. Reservoir Scale Sandbody Architecture of Pliocene Turbidite Sequences, Long Beach Unit, Wilmington Field, California. Paper SPE 26440, presented at the 1993 Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October. 33. Pemex E&P. 2000. Informe Final de la Prueba Piloto del Campo Agua Fría. Internal Report. 34. Protechnics. 2000. Interwell Tracer Program Initial Summary Report Agua Fria Field, Prueba Waterflood Pilot Area. Pemex E&P, Internal Report. 35. Nikitin, A.; Shirnen, A. 2007. Complex Fracture Geometry Investigations Conducted on Western-Siberian Oil Fields at Rosneft Company. Paper SPE 109909, presented at the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November.
36. Nikurova, L. F.; Surtaev, V. N. 2006. Enhancing Well Productivity After Hydraulic Fracturing in the Priobskoe Oilfield. Paper SPE 102194, presented at the 2006 SPE Russian Oil and Gas Technical Conference and Exhibition, Moscow, Russia, 3-6 October. 37. Rivera, R., J. 2003. Mojabilidad de las Rocas de Tajin y Agua Fria. Pemex E&P, Internal Report. 38. Robin, Michel; Rosenberg, E. 1995. Wettability Studies at the Pore Level: A New Approach by Use of Cryo-SEM. Paper SPEFE 22596, March, 11-19. 39. Rodriguez D., M. 2001. Prueba Piloto y Perspectivas de Inyección de Agua Congenita en el Campo Agua Fria. Ingenieria Petrolera, Vol. XLI, No. 10. 40. Salathiel, L. A. 1973. Oil Recovery by Surface Film Drainage in Mixed-Wettability Rocks. JPT (Paper SPE 4104), October, 1216-1224. 41. Shandrygin, A. N.; Lutfullin, A. 2008. Current Status of Enhanced Recovery Techniques in the Fields of Russia. Paper SPE 115712, presented at the 2008 SPE Annual Technical Conference and Exhibition, Denver, Colorado, 2124 September. 42. Tyler, Noel; Gachuz-Muro, Heron; Rivera-Rodriguez, Jesús. 2004. Integrated Characterization of Low Permeability, Submarine Fan Reservoirs for Waterflood Implementation, Chicontepec Fan System, Mexico. Paper SPE 92077, presented at the 2004 SPE International Petroleum Conference, Puebla, Mexico, 8-9 November. 43. Woodling, G. S.; Taylor, P. Y. Layered Waterflood Surveillance in a Mature Field: The Long Beach Unit. Paper SPE 26082, presented at the 1993 SPE Western Regional Meeting, Anchorage, Alaska, 26-28 May.