SPE 89411

Enhanced Oil Recovery by Steamflooding in a Recent Steamflood Project, Cruse ‘E’ Field, Trinidad V. Ramlal, SPE, Petrotrin Copyright 2004, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2004 SPE/DOE Fourteenth Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, U.S.A., 17–21 April 2004. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Based on the success of the Cruse ‘E’ Pilot steamflood, Petrotrin decided to venture into a large-scale thermal project called the Cruse ‘E’ (IADB) Expansion Steamflood. The project area consists of 270 acres in the zone of interest, the Upper Cruse ‘E’ sand. Surface and infrastructure work began in January 1994, and was followed by rig work - drilling, recompletions, and workovers. Sixty (60) new wells comprising twenty-eight (28) injectors and thirty-two (32) offtakes were drilled and completed to form twenty-eight (28) patterns. Also thirty-five (35) existing wells were utilized as offtakes. The project was commissioned in January 1996 when steam injection began. It was predicted in 1992 by reservoir simulation that 11 million barrels of heavy oil would be recovered over fifteen (15) years with production peaking in the year 2000.

However, in 1998 when oil production reached 900 bopd, the project was adversely affected by environmental concerns to a residential area in the vicinity of the steamflood and it was actually shutdown by order of the Environmental Management Agency in November 1998. Extensive environmental work was undertaken by Petrotrin in the areas of communication, training and operations to improve the safety and environmental aspects of the steamflood, and ensure that it was brought up to required environmental standards. After forty (40) months of inactivity, approval was finally obtained in March 2002 from the environmental regulatory agency to restart steam injection.

This paper discusses the performance of the steamflood during steam injection and during no injection, the operational

and economic aspects of the project, and the environmental upgrade conducted. The paper also discusses the production response since restart, the amended forecast from history-matched reservoir simulation and future operating strategies. Introduction The Cruse ‘E’ (IADB) steamflood is situated in the southwestern part of Trinidad in the Parrylands area, about 8 miles from the town of Point Fortin [Fig. 1]. It is one of several active thermal projects being operated by Petrotrin, and is the most recent steamflood developed by the company. Some of the very mature steamfloods have been converted to heat scavenging projects. Oil production from these thermal projects and heat scavenging schemes account for eighty percent [80%] of EOR production.

The Cruse ‘E’ Expansion Steamflood was undertaken following the success of the Cruse ‘E’ Pilot Project. With loan financing from the Inter-American Development Bank, twenty-eight [28] new patterns were formed by drilling sixty [60] wells and incorporating thirty-five [35] existing wells in the thermal area [Fig. 2]. Steam generation and distribution equipment and production facilities were installed during 1995 and actual steam injection began in January 1996. The shallow Cruse ‘E’ sands were ideal for steamflooding, and as a result response was obtained in just nine (9) months. Twenty-two (22) months later production reached 1200 bopd. For environmental reasons, the flood was shut down in November 1998 and approval was not obtained to re-start until March 2002.

The factors that will contribute to the success of this project are: (a) high reserves of shallow heavy oil of average 17o API. (b) reliable, adequate supplies of fresh water for injection

and natural gas for steam generation.

(c) good reservoir continuity with the project limits.

(d) the accumulated expertise gathered in the past thirty [30] years in enhanced oil recovery from Petrotrin’s predecessor companies.

(e) the success of the Pilot Project.

2 SPE 89411

The Cruse ‘E’ Pilot Project The Cruse ‘E’ Pilot Project commenced in 1986 with four [4] inverted five-spot patterns and extended over an area of forty [40] acres. The sand exploited is the Cruse ‘E’ sand which is located at an average depth of 1800 ft and with a net oil sand thickness average of 120 ft. Each pattern has one or two central injectors and the displacement mechanism is by steam drive.

In February 1986 cyclic steam stimulation was attempted in the Pilot Project to test the applicability of the process to the reservoir, which had a seventeen percent [17%] recovery from primary production. In 1987 another pattern was added to the north of the existing flood, and in 1988 two [2] more patterns were added to the south-west to form what is referred to as the 2P/3P project.

Injection rate averaged 1800 bspd during 1986-1990 and oil production peaked at 300 bopd in 1987. The Pilot Project is still active and cumulative oil production from start of steamflooding to date is 1.65 million barrels oil, which represents a recovery factor of 33 %. Geology of Cruse ‘E’ Sands The project is situated in Point Fortin/Cruse area and has acreage in three [3] fields – Point Fortin Central, Point Fortin East, and Cruse Fields. It lies just north of the Los Bajos fault system along the northern flank of the east-west trending Point Fortin anticline feature.

The associated structure is that of a NNE gently dipping anticline limits. Dips are non-uniform and range from 45o in the south to 4o NNE in the down dip areas to the north and east. The project area is roughly bounded by two [2] north-west/south-east trending faults. These faults are controlled by seismic data and are related to the major Los Bajos fault system. Fig. 3 is a structure map of the project area.

The primary objective is the uppermost section of the Pliocene Upper Cruse formation. It represents a major regressive deltaic sequence deposited in a high stand system tract. The objective sands are uncomformably overlain by a thick shale sequence known as the Lower Forest Clay. It represents the upper transgressive system tract. This regional transgressive shale forms the effective upper seal of the reservoir. The objective sands are interpreted to consist of north-east/south-west trending distributary channel/mouth bar complexes, which were deposited, in a lower deltaic plain environment. It consists of several stacked discrete, mappable, elongate reservoirs with distinct shale out edges, which attain an average gross maximum thickness of 150 feet. The objective interval are separated into four [4] mappable units, namely, the stratigraphically lowermost Unit ‘A’ to the uppermost Unit ‘D’. Each unit is separated from the overlying and underlying units by distinct shales. A type log is shown in Fig. 4. Best sand development occurs in Units ‘B’ and ‘C’. Four (4) oil sand isopach maps for Units ‘A’ to ‘D’ are in Figs. 5 – 8.

Reservoir closure to the north and south of the project area is provided by shale out. The reservoir is limited to the east by shale out and water levels in a down dip position. Reservoir Engineering and Production Forecast Drilling of sixty [60] new wells provided information that led to a better understanding of the reservoir, especially marker depths and fault positions. As a result, several faults such as Fault 101, Fault 185 and Fault 420 were confirmed from contour misties and fluid anomalies.

The patterns were originally intended to be inverted 5-spots, but because of the presence of faults and actual positions of wells, their configurations had to be revised and as a result, pattern areas range from 3.8 to 11.0 acres. Twenty-eight [28] patterns were completed with a total project area of 270 acres. Fence diagrams were done for all patterns.

Two [2] wells, FC 416 and CR 154 were full hole cored within the objective Upper Cruse sands to determine accurate reservoir rock and fluid properties. A summary of the reservoir rock and fluid properties is given in Table 1.

Primary production accounted for seventeen percent [17%]

of the original-oil-in-place. The oil-in-place at start of steamflood was estimated to be 31.1 million barrels. Assuming an ultimate recovery factor of 33%, the recoverable reserves by steamflooding is estimated to be 10.3 MMBBL. The recovery to date is 3.3% of OIP at start of steamflood.

Actual field data derived from wells in the Pilot Steam

Project was used to estimate the production performance of the wells in this expansion steam project. For example, in the Pilot Project the following observations were made: (1) wells responded favorably to cycles 1 and 2 of cyclic

steam stimulation, while cycles 3 and onwards were not as favorable.

(2) duration of the first cycle was nine [9] months, with

average injection rate of 300 bspd. Subsequent cycles were of progressively shorter periods.

(3) the volume of oil recovered per well per cycle averaged

6000 bbls and 3500 bbls for cycles 1 and 2 respectively.

The initial steam drive performance was predicted using

the Jeff-Jones analytical model, which was based on a modification of Myhill-Stegemeier. A base case production forecast was done using average properties of the Cruse ‘E’ rock and fluids. In the ‘most likely’ scenario, a total of 10.3 million bbls oil was expected to be produced in a fifteen [15] year span with peak oil production of 3800 bopd occurring in the year 2001. This forecast is shown in Table 2. Production and Injection The production and injection profile for the Cruse ‘E’ Expansion steamflood is shown in Fig. 9. Steam injection was started in January 1996, and increased to 10,000 bspd. There

SPE 89411 3

was almost immediate response to steam injection, and oil production climbed quickly to 1100 bopd by November 1997. Injection volumes were decreased to 7,500 bspd in November 1997 because of high water cuts in some offtakes, but this had a downward effect on production which fell to 850 bopd [Fig. 10]. Injection was stopped by order of the Ministry of Energy in November 1998, because of reports of harmful gases in the atmosphere having adverse effects on nearby residents. Cessation of injection caused production to plummet to 140 bopd by November 1999. After all requirements set out by the regulatory bodies were met by Petrotrin, the Ministry of Energy granted approval to re-commence activity in this project in March 2002, subject to certain operating conditions.

The project is serviced by five [5] 50 MMBTU steam generators having a combined maximum output of 15,000 bspd. Water for the generators are obtained from water wells in Forest Reserve, which is softened and treated to remove oxygen and bacteria. The generators discharge pressures are about 1000 psi and they are capable of delivering steam of 80% quality. The entire steam distribution system is insulated with magnesia and aluminum.

The cumulative steam-oil-ratio [SOR] up to when injection

was stopped was 9.65, while the instantaneous SOR at that time was 11.0. Actual production was close to predicted up to November 1997, but fell back when injection was reduced because of high water production in some wells. Response since Restart Because the scheme was closed in for an extended period of time almost all the wells had returned to ambient temperature. Steam injection was actually re-started in November 2002 using two [2] 50 MMBTU generators initially and injecting at 300 bspd per injector. A third generator came on in December 2002 and injection rates in selected patterns were increased to 500 bspd. Pattern performance is reviewed on a quarterly basis, and injection targets are adjusted accordingly so as to facilitate heating of the reservoir. The response time was expected to be 6 to 9 months, but several patterns showed stimulation after three (3) months. To date, the scheme’s production has increased from 158 bopd in November 2002 to 1150 bopd in November 2003. Steamflood Performance Some of the techniques used to monitor the production performance of the steamflood are: 1. Pattern plots which are graphical representations of oil

and water production for each pattern. 2. Injectivity plots which are graphs of injection rates and

injectivity versus time for each injector.

3. Fluid maps for contouring and tracking flood movement e.g. iso-gross, iso-nett, iso-watercut. There are also iso-temperature for showing temperature distribution, iso-basic for reservoir pressure and iso-cumulative for cumulative oil spread.

4. Temperature surveys to monitor downhole temperature profile of injectors and offtakes.

5. Heat loss calculations, which give an indication of

steam quality at the surface and downhole.

Pattern plots for Cruse ‘E’ indicate that all the patterns have shown response to steam, but to varying extents. The most prolific pattern during 1998 using oil production as yardstick was Pattern 2 which had a potential of 160 bopd. These plots also indicate that there were suddenly high water cuts in Patterns 3,4,5,6,15,20 and 25, which were due to some wells producing large volumes of water. These wells were causing improper distribution of steam in the reservoir and were closed in or tailored down when excessive water production began. Also, steam injection rates in the patterns were either reduced or stopped.

The sands are receptive to steam injection; with injection rates as high as 1000 bspd being recorded. The average injection rate during the 1996-1998 period was 500 bspd per injector, which corresponds to an average injectivity of 0.63 bspd/psi.

The areal pattern sweep is irregular. In some cases it follows the sand thickness trend of the ‘B’ and ‘C ‘sands, while in other patterns, it does not. This is confirmed by the iso-gross, iso-nett and iso-water cut maps of 1998 [Figs. 11-13]. There is poor vertical conformance in some patterns, which is confirmed by pre-mature breakthrough in some offtakes, as well as temperature distribution across the perforations in injectors. Hence, it is necessary to run RST logs to measure water saturation close to the wellbores of such offtakes, so that water shut-offs can be recommended. Also, it will be necessary to change injection points from time to time. Environmental Aspects The Cruse ‘E’ Pilot and Cruse ‘E’ [IDB] Expansion steamfloods were closed in by the Ministry of Energy in November 1998 following several reports by nearby residents of harmful gases in the atmosphere. A school and kindergarten in close proximity to the scheme were of major concern. Baseline ambient air quality sampling was conducted and the sample sent to the United States for testing. Results indicated that there were unacceptably high levels of volatile organic compounds [VOC’s] present during certain types of weather and during certain field activities. A Pan American Health Organization [PAHO] survey listed the possible sources of pollution and made recommendations for corrective measures. During 1999-2000 corrective measures were aggressively pursued by Petrotrin, and the following activities were accomplished: - (1) More than twenty [20] meetings were held comprising

representatives from Petrotrin and all external stakeholders such as Ministry of Energy, Ministry of Environment, Ministry of Education, Environmental Management Agency, and Parrylands Community Leaders.

4 SPE 89411

(2) Operations and Communications Plans were developed and presented to the Ministry of Energy [MOE] and the Environmental Management Agency [EMA].

(3) An Air Quality Plan was developed for measuring and

monitoring ambient air quality in Parrylands and other selected areas.

(4) An Emergency Response Plan was developed to

address any upset conditions that may arise during Cruse ‘E’ operations. The plan was tested with an exercise that involved all stakeholders.

(5) Petrotrin’s Standard Field Operating Instructions

[SFOI’s] were revised for conducting production operations in Cruse ‘E’, and they were approved by the Ministry of Energy.

(6) More than one hundred and fifty [150] persons

comprising Petrotrin and contractor personnel were trained on SFOI’s, hydrogen sulphide awareness, and other safety procedures.

(7) Seven [7] steam injectors located in close proximity to

the Parrylands Village and Parrylands school were isolated, as was recommended by PAHO/MOE/EMA.

(8) Hydrogen sulphide was removed from the gas stream

by the installation of Sulfa Treatment Systems prior to venting to the atmosphere at Gathering Station 9 and 40. Also, wells were treated for removal of hydrogen sulphide using an approved H2S scavenger. The treatment was also done to any well that produces H2S, prior to the commencement of winch work.

(9) The Parrylands school was re-located and the building

converted to a Community Center for surrounding villagers. Petrotrin also constructed a football field, basketball and netball courts adjacent to the Community Center. Employment and training opportunities are provided to residents of Parrylands.

Approval was formally granted to re-commence steam injection in Cruse ‘E’ Expansion and Cruse ‘E’ Pilot in March 2002 by the Ministry of Energy, subject to the following conditions:- (1) The steam lines to seven [7] patterns located close to

the school and the village to be disconnected and blanked off.

(2) Weekly checks for H2S and VOC’s to be conducted by

Petrotrin at all locations recommended by the Ministry of Energy, and the monitoring data must be submitted to the Environment Management Agency.

(3) Periodic sampling and analysis of air in the vicinity of

the Parrylands Village to be done at Petrotrin’s expense, to determine levels of VOC’s in accordance with US EPA methods.

Following the approval by MOE to re-start steam injection, the following preparatory works were conducted:- (1). Tested and inspected [T & I] the five [5] steam

generators in Cruse ‘E’. (2) Upgraded the entire steam distribution network.

(3) Conducted routine workovers on forty-one [41] wells.

Noise levels from rig work was kept at <70 decibels at a distance of 20 feet from the rig.

(4) Performed coil cleanout jobs to all injectors. Reservoir Simulation Results of History Match and Simulation Two analytical models were used, the Myhill-Stegemeier and the Jeff Jones models. (a) Results of Myhill-Stegemeier Analytical Model The Myhill-Stegemeier model was used to simulate the 28 patterns. The production value it gives at the beginning of the steamflood is higher than the actual. This can be seen in Fig. 14, which is a history match and forecast of the project using both models. The actual production in 1996 was 482 bopd and the Myhill-Stegemeier value was 1099 bopd. In 1997, when the scheme peaked at 1142 bopd, the Myhill-Stegemeier value was 1656 bopd.

This model predicts a peak production of 2601 bopd in 2004, which will decline to 2209 bopd in 2005. A final recovery factor of 52 % of OOIP (11.29 MMbbls of oil) would be achieved over the next twenty (20) years. Recoveries ranges from as low as 30% in pattern 4 to as high as 81% in pattern 2. The steam-oil-ratio history match and forecast is shown in Fig. 15 for both models. For the Myhill-Stegemeier model an SOR of 3.2 could be expected when the scheme reaches its peak in 2004, which will move to 4.8 in 2008 and continue to increase to 7.7 at the end of the projected time. The Myhill-Stergemeier forecast of the IADB Cruse ‘E’ Expansion steamflood meets and satisfies Chu’s correlations on steam flooding i.e. SOR > (or equal to) 5.0 (b) Results of Jeff Jones Model Jeff Jones identified three stages in a steam flood scheme Stage I, Stage II and Stage III... During Stage I, the reservoir does not instantaneously realize the effects of the thermal recovery phenomena. Instead, because of the large difference in mobility between the displacing steam and the cold oil, there is channeling and this affects initial production response. The Jeff Jones method history match of production of this steamflood in year 1996 is 355 bopd less that the actual, as can be seen in Fig. 14. In 1997, when the scheme was producing 1142 bopd, this model gave a value that was 91 bopd higher than the actual.

SPE 89411 5

At Stage II of a thermal scheme, the mobility of the oil increases, and is largely due to viscosity reductions. As a result, hot oil is displaced towards the offtakes very efficiently and the production rate is about equal to the rate of growth of the steam chamber. The peak production occurs early in this Stage.

At Stage III of the process, there are substantial vertical

heat losses to the adjacent formations, but this is not sufficiently accounted for in this model. As a result, production will not decline to zero with time, unless manually declined.

A peak production of 2164 bopd is forecasted in year 2005,

which will decline to 1705 bopd in 2006. By year 2010 it will be 1073 bopd and end off at 148 bopd in 2023. The final recovery factor of 44 % of OOIP (10.08 MMbbls of oil) would be achieved at the end of the projected time. The steam-oil-ratio results for this method is shown in Fig. 15. It is forecasted to be 3.5 when the scheme reaches its peak in 2005, increase to 4.9 in 2008 and reach a maximum of 14.9 at the end of the projection.

Of the two (2) simulation models used, the Jeff Jones gives

a closer history match than the Myhill-Stegemeier. The latter predicts very early and rapid response. It was observed that the Jeff Jones model generates higher SOR’s than the Myhill-Stegemeier as the project reaches maturity. Based on these results, it is felt that the Jeff Jones model is the preferred choice over the Myhill-Stegemeier as an analytical simulator for this project.

A simulation of this steamflood using the numerical

simulator CMG STARS is in progress. Geologic and reservoir maps of the Cruse ‘E’ sub-units are being formatted for the software, at the time of writing of this paper. Future Operating Strategies The operating strategy of this steamflood will incorporate a combination of the following activities:

• Introduction of cyclic steaming in this scheme. At present five (5) wells are being prepared for cyclic steaming.

• Improvement of steam quality at the wellhead.

Damaged or stolen steam line lagging is replaced on a continuous basis.

• Activate more patterns. Petrotrin will seek approval

from the Energy Ministry in 2004 to waterflood the seven patterns that are closed in for environmental reasons.

• Identify cause of early water breakthrough in some

wells, by investigating vertical conformance at injector and offtake. RST logs will be run on some offtakes with high water cuts.

• Unreliable supply of water to the generators is to be addressed, by increasing the number of active water wells in Forest Reserve.

• Application of new technology to monitor and

improve steamflood performance, for example, cross-well tomography, additives to steam, use of foaming agents as diverters, and 4-D seismic.

Project Economics The original project economics of May 1996 was severely affected by the four-year shutdown of steam injection. A revised production forecast was done in November 2002 with the assumption that the remaining recoverable reserves of 7.5 MMBO will be produced in 13 years with a peak of 2200 bopd in year 2006 [Table 2]. Economic runs were done to include capital expenditure incurred during the re-start phase. Results of economic runs indicate that the project will be profitable at a market oil price of $18.00 per barrel and above. Cruse ‘E’ thermal oil has a market value of $US 6.00 less than WTI crude.

The annual economics of the project is based on the Economic Limit Steam Oil Ratio Method, which is used for the other Petrotrin steamfloods. In this method, the economic limit steam-oil ratio is calculated based on an operating cost target, steam generator cost and a total actual operating cost of the steamflood. If R = Project Steam Cost Project Operating Cost It could be shown that: Economic Limit SOR = (Operating Cost Target)(R) (Cost to generate a bbl of steam)

For example, for the year 2003, the operating cost target was $US 7.50/bbl oil and the ratio R was 0.70, which together with an average steam generation cost of $US 0.75 per bbl steam gives an Economic Limit SOR of 7.0 for that year. The actual SOR for the year 2003 was 6.16, which is less than the Economic Limit SOR, which means that the steamflood operating cost was less than the cost target set by the company. During 2003, it was necessary to inject at high rates, even though not very profitable, so as to fill up and heat up the reservoir after four (4) years of non-injection. The injection to withdrawal ratio for the year was 2.8. Conclusions (1) The interpreted bifurcating ENE/WSW trend of the

distributary channel complexes of the uppermost section of the Upper Cruse sands which were sub-divided into Units A, B, C and D was confirmed by the many wells that were drilled. The presence of several faults was confirmed by contour misties and fluid anomalies

6 SPE 89411

(2) The oil in place [OIP] at the start of steamflood was estimated to be 31.1 MMBBLS. The recovery to date is 3.3%. The remaining reserves are expected to be produced over the next twelve [12] years with a peak production rate of 2200 bopd occurring in year 2005, based on no injection in seven [7] patterns and an ultimate recovery factor of 28%.

(3) There is evidence of uneven sweep and poor vertical

conformance in several patterns. More reservoir engineering type work is needed to overcome production problems, especially high water cuts. Since injection was restarted in November 2002, response has been better than expected.

(4) History-matches and performance predictions were

done using two (2) different analytical models, Myhill- Stegemeier and Jeff Jones. The Jeff Jones model produces a closer history match and a more realistic early response than the Myhill-Stegemeier model.

(5) Environmental standards in the field and

communication with residents have improved since the scheme was shut down. Since steam injection has re-started, greater emphasis is being placed on upkeeping the environmental standards of an active steamflood operation, as the scheme will be hoping for ISO 14001 certification.

(6) The economics of the project was severely affected by

the four [4] year shutdown of steam injection. Revised economics show that the project will be profitable at market oil prices of $US 18.00 per barrel and above.

Acknowledgements I would like to thank the Management of Petroleum Company of Trinidad & Tobago [Petrotrin] for permission to publish this paper. I would also like to thank the Geoscientists and Production personnel who have worked, and who are currently working to make this project a success.

References

1. Ali-Nandlal, J. : “Review of the Point Fortin Cruse ‘E’ Pilot and 2P/3P Steam Projects”, P.E. Report No. 280, Reservoir Development Department, Petroleum Company of Trinidad & Tobago Limited, 1994 May.

2. Greaser, Gary R. : “New Thermal Recovery Technology and

Technology Transfer for Successful Heavy Oil Development”, Paper SPE 69731, presented at SPE International Thermal Operations and Heavy Oil Symposium, Margarita Island, Venezuela, 2001 March 12-14.

3. Marcelle-de Silva, J. : “Point Fortin Cruse ‘E’ Expansion Steamflood

– Production Forecast Sensitivity Analysis”, P.E. Report No. 253, Technical Department, Trinidad & Tobago Oil Company, 1992 August.

4. IADB Implementation Team : “Revised Project Scope for Point Fortin Cruse ‘E’ Steamflood Expansion Project” : P.E.. Report No. 279, Exploration & Production Division, Petroleum Company of Trinidad & Tobago Limited, 1994 March.

5. IADB Implementation Team : “Technical Report (subsurface) for

Point Fortin Cruse ‘E’ Steamflood Expansion Project”, P.E. Report No. 299, Exploration & Production Division, Petroleum Company of Trinidad & Tobago Limited, 1996 May.

6. Prats, Michael: “Thermal Recovery,” Monograph Volume 7, Society

of Petroleum Engineers, Henry L. Doherty Series. 7. Sumadh, W., Ramoutar, R. : “Geological Study of the Pliocene

Upper Cruse Sands in the Cruse ‘E’ Pilot Area and Proposed Eastern Expansion Area of the Fortin Central and Cruse Fields”, Geological Report No. 680, Reservoir Development Department, Petroleum Company of Trinidad & Tobago Limited, 1994 June.

8. Ramlal, V.:”The Cruse ‘E’ Expansion Steamflood: Technical,

Economic and Environmental Perspectives”, Paper SPE 81063 presented at LACPEC VIII, Port of Spain, Trinidad, 2003 April 27-30.

SI METRIC CONVERSION FACTORS

Acres x 4.046856 * E-01 = ha

Bbl x 1.589873 E-01 = m3

Cp x 10 * E-03 = Pa.s

(degree F - 32)/1.8 E-00 = °C

ft. x 3.048 * E-01 = m

in. x 2.54 * E-00 - cm

md x 9.869233 E-04 = um2

psi x 6.894757 E+00 = kPa

* Conversion factor is exact

SPE 89411 7

Average Depth to Base of Sand (ft) 2100 Average Reservoir Temperature at start of steamflood ( o F) 110 Average Crude Oil Viscosity at reservoir conditions (cp) 175 Crude Gravity at 60 o F ( o API) 16 - 18 Average Permeability (md) 265 Average Sand Thickness (ft) 75 Average Porosity (%) 31 Area (acres) 270 Initial Oil Saturation (%) 75 Estimated Oil Saturation at start of Steamflood (%) 68 Formation Volume Factor (Res bbl/stb) 1.1 Original Oil in Place (MMBBL) at start of steamflood 31.1

TABLE 1 - CRUSE 'E' (IADB) EXPANSION STEAMFLOOD SUMMARY OF RESERVOIR

YEARORIGINAL

FORECAST OF 1995

REVISED FORECAST

OF 2002

FORECASTED INJECTION

ACTUAL PRODUCTION

ACTUAL INJECTION

(BOPD) (BOPD) (BSPD) (BOPD) (BSPD)1995 150 156 0 0.001996 450 417 5,017 12.031997 1,350 810 9,372 11.571998 2,375 877 6,525 7.441999 3,275 280 - 0.002000 3,775 148 - 0.002001 3,760 163 - 0.002002 3,400 144 400 2.782003 2,900 600 6,000 831 5,115 6.162004 2,375 1,000 10,000 10.002005 1,825 1,500 10,000 6.672006 1,250 2,000 10,000 5.002007 800 2,200 10,000 4.552008 400 2,200 8,000 3.642009 150 2,000 7,000 3.502010 1,700 6,000 3.532011 1,350 5,000 3.702012 950 4,000 4.212013 700 3,000 4.292014 500 2,500 5.002015 350 2,000 5.71

STEAM OIL

RATIO

TABLE 2 - CRUSE 'E (IADB) EXPANSION STEAMFLOODFORECASTED AND ACTUAL PRODUCTION AND INJECTION SUMMARY

8 SPE 89411

FIG. 1 -PETROTRIN THERMAL PROJECTS LOCATION MAP

Steamflood and Heat ScavengingProjects

FIG. 1 -PETROTRIN THERMAL PROJECTS LOCATION MAP

Steamflood and Heat ScavengingProjects

FIG. 2 – CRUSE ‘E’ (IDB) STEAMFLOOD – PATTERN MAPFIG. 2 – CRUSE ‘E’ (IDB) STEAMFLOOD – PATTERN MAP

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FIG. 3 – CRUSE ‘E’ (IDB) STEAMFLOOD – STRUCTURE MAP TOP CRUSEFIG. 3 – CRUSE ‘E’ (IDB) STEAMFLOOD – STRUCTURE MAP TOP CRUSE

FIG. 4 – TYPE LOG – CRUSE 166FIG. 4 – TYPE LOG – CRUSE 166

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FIG. 5 – CRUSE ‘E’ (IDB) STEAMFLOOD – NET OIL SAND ISOPACH UNIT AFIG. 5 – CRUSE ‘E’ (IDB) STEAMFLOOD – NET OIL SAND ISOPACH UNIT A

FIG. 6 - CRUSE ‘E’ (IDB) STEAMFLOOD – NET OIL SAND ISOPACH UNIT BFIG. 6 - CRUSE ‘E’ (IDB) STEAMFLOOD – NET OIL SAND ISOPACH UNIT B

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FIG. 7 - CRUSE ‘E’ (IDB) STEAMFLOOD – NET OIL SAND ISOPACH UNIT CFIG. 7 - CRUSE ‘E’ (IDB) STEAMFLOOD – NET OIL SAND ISOPACH UNIT C

FIG . 8 - C R U SE ‘E ’ (ID B ) ST E A M FL O O D – N E T O IL SA N D ISO PA C H U N IT D

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FIG 9 - CRUSE 'E' EXP (IADB) STEAMFLOOD PROJECTOIL PRODUCTION / INJECTION PROFILE

0

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9M

ay-9

9Ju

l-99

Sep-

99N

ov-9

9Ja

n-00

Mar

-00

May

-00

Jul-0

0Se

p-00

Nov

-00

Jan-

01M

ar-0

1M

ay-0

1Ju

l-01

Sep-

01N

ov-0

1Ja

n-02

Mar

-02

May

-02

Jul-0

2Se

p-02

Nov

-02

Jan-

03M

ar-0

3M

ay-0

3Ju

l-03

Sep-

03N

ov-0

3

1995 JANUARY - 2003 NOVEMBER

OIL

PR

OD

UC

TIO

N (B

OPD

)

0

2000

4000

6000

8000

10000

12000

STEA

M IN

JEC

TIO

N (B

SPD

)

OIL (BOPD) STEAM INJECTED (BSPD)

Injection Stopped

Injection Recommenced

FIG. 10 - CRUSE 'E' EXP (IADB) STEAMFLOOD PROJECTWATER-CUT / GROSS PROFILE

0

1000

2000

3000

4000

5000

6000

Jan-

95M

ar-9

5M

ay-9

5Ju

l-95

Sep-

95N

ov-9

5Ja

n-96

Mar

-96

May

-96

Jul-9

6Se

p-96

Nov

-96

Jan-

97M

ar-9

7M

ay-9

7Ju

l-97

Sep-

97N

ov-9

7Ja

n-98

Mar

-98

May

-98

Jul-9

8Se

p-98

Nov

-98

Jan-

99M

ar-9

9M

ay-9

9Ju

l-99

Sep-

99N

ov-9

9Ja

n-00

Mar

-00

May

-00

Jul-0

0Se

p-00

Nov

-00

Jan-

01M

ar-0

1M

ay-0

1Ju

l-01

Sep-

01N

ov-0

1Ja

n-02

Mar

-02

May

-02

Jul-0

2Se

p-02

Nov

-02

Jan-

03M

ar-0

3M

ay-0

3Ju

l-03

Sep-

03N

ov-0

3

1995 JANUARY - 2003 NOVEMBER

GR

OSS

PR

OD

UC

TIO

N

(BPD

)

0

10

20

30

40

50

60

70

80

90

100

WA

TER

-CU

T (%

)

GROSS FLUID (BFPD) WATER-CUT (%)

Injection Stopped

Gross

Water-cut

Injection Recommenced

SPE 89411 13

FIG. 11 – CRUSE ‘E’ (IDB) STEAMFLOOD –ISO GROSS MAP (BFPD)

FIG. 12 – CRUSE ‘E’ (IDB) STEAMFLOOD –ISO NET MAP (BOPD)

14 SPE 89411

FIG. 13 – CRUSE ‘E’ (IDB) STEAMFLOOD –ISO WATER-CUT MAP (%)FIG. 13 – CRUSE ‘E’ (IDB) STEAMFLOOD –ISO WATER-CUT MAP (%)

SPE 89411 15

FIG. 14 - IADB Cruse 'E' Expansion Steamflood Forecastusing both the Myhill Stergemeier and Jeff Jones Method

0

250

500

750

1000

1250

1500

1750

2000

2250

2500

2750

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

Time (Years)

Fore

cast

(BO

PD)

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

Stea

m In

ject

ion

Rat

e (B

SPD

)

Jeff Jones Myhill Stergemeier Actual Steam Rate

FIG. 15 - STEAM OIL RATIO Forecast for both the Myhill Stegemeier and Jeff Jones Method

0

5

10

15

20

25

30

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

Time (Years)

SOR

(bb

ls/b

bls)

Jeff Jones (SOR) Myhill Stegemeier (SOR)

injection restarted Nov-02