current status of commercial in situ combustion projects worldwide
TRANSCRIPT
November 2007, Volume 46, No. 11 1
Current Status of Commercial In Situ Combustion Projects Worldwide
A.T. TurTA Alberta research Council
S. K. ChATTopAdhyAy, r.N. BhATTAChAryA oil and Natural Gas Corporation (oNGC), India
A. CoNdrAChI oil and Gas research Institute (petrom), romania
W. hANSoN Bayou State oil Corporation, uSA
Peer reviewed PaPer (“review and Publication Process” can be found on our web site)
AbstractThis paper gives essential information on two commercial
in situ combustion (ISC) projects in India, one commercial ISC project in Romania and one commercial ISC project in the USA.
The ISC project at Suplacu de Barcau, Romania is the largest project of its kind, and it has been in operation for 34 years as a dry ISC process. The Balol and Santhal projects in India have been in operation for more than seven years, and have been ap-plied in a wet mode. Currently, these three projects produce more than 500 m3/day (3,450 bbl/day) from each project, while all three combined produce approximately 2,300 m3/day (15,860 bbl/day). Additionally, the project operated by Bayou State Oil Corporation (BSOC) in Bellevue, Louisiana, USA produces 51 m3/day (320 bbl/day). This total amount of 2,350 m3/day repre-sents the total amount of heavy oil produced by ISC today.
Alex Turta is a research leader for Im-proved Oil Recovery at Alberta Research Council (ARC) in Calgary. His research interests include primary recovery of heavy oils, waterflooding of light oils, and thermal recovery methods for heavy oil. He has extensive experience of heavy oil exploitation, from laboratory to field pilots, and has undertaken international consultancy for thermal pilot evaluation. He assisted in the development of PRI’s enhanced oil recovery evaluation soft-ware PRIze. Alex holds M.Sc. and Ph.D.
degrees from the University of Oil and Gas and Petroleum En-gineering, Bucharest, Romania, and worked previously at the Research and Development Institute for Oil and Gas, Campina, Romania. He is a co-inventor of the THAI and CAPRI processes for heavy oil recovery and upgrading, and is a member of SPE, the Petroleum Society and the Canadian Heavy Oil Association.
Dr. S.K. Chattopadhyay is Chief Chemist for the Oil and Natural Gas Cor-poration (ONGC) Ltd., India, working at the Mehsana Asset. He joined ONGC Ltd. in 1983 as a Graduate Trainee in Chem-istry. Over the last 24 years at ONGC, he has gained experience working at dif-ferent offshore and onshore production installations, the LPG/CSU/C2-C3 pro-cess control laboratory, onshore drilling rigs, the in situ combustion process mon-itoring laboratory and, presently, he is working in a multi-disciplinary team for
the monitoring, interpretation and process control of the commer-cial in situ combustion process at the Balol and Santhal Fields of the Mehsana Asset, India. Dr. Chattopadhyay has presented sev-eral technical papers on the in situ combustion process at var-ious national and international conferences and symposiums. He graduated with a Ph.D in chemistry from the University College of Science, Calcutta University, India.
R.N. Bhattacharya is the General Man-ager (Reservoir) for the Oil and Natural Gas Corporation (ONGC) Ltd., India, working at the Mehsana Asset. He is presently working on the company’s commercial in situ combustion scheme in Western India. Mr. Bhattacharya has had experience working on different as-sets and projects for ONGC, including
GUEST EDITORIALGUEST EDITORIAL
overseas projects. He has over 30 years of oil industry experi-ence as petrophysicist, reservoir engineer and in contract moni-toring. Mr. Bhattacharya earned an M.Sc (physics) in 1972 and M.Sc. (geophysics) from Banaras Hindu University, India. He studied reservoir engineering at the India School of Mines (ISM), India, the University of Austin and Stanford University, USA. He is the author of several technical papers and numerous technical reports.
Alexandru Condrachi is a Reservoir Engineer for PETROM S.A. Member of OMV Group, E&P Central Region Divi-sion, Ploiesti. He earned a B.C., M.S. and Ph.D. degrees from the Petroleum-Gas University of Ploiesti, Romania.
Wayne Hanson has been with the Bayou State Oil Corporation (BSOC), Bellevue, Louisiana since 1980. Initially, he served as a Petroleum Chemist, and starting from 1990, he has been Supervisor of the BSOC In Situ Combustion Project. Wayne has M.S. and Ph.D. degrees from the Uni-versity of Houston. He was a Chemistry Department Chairman at Centenary Col-lege in Shriveport, Louisiana from 1959 to 1979.
2 Journal of Canadian petroleum Technology
Introduction
Patented in 1920 in the USA, the first very short-term in situ combustion field pilot (actually the first ignition operation) took place in the former Soviet Union in 1933 – 1934, while the true testing of an in situ combustion (ISC) process occurred in the USA in 1950 – 1951. Since 1950, more than 162 ISC field pilot projects have been in operation. The process has been extensively studied both in laboratory and in field pilots. In the 1970 – 1980 period, a maximum of 19 commercial ISC projects were recorded. How-ever, this number decreased steadily to four active commercial processes, currently.
In 1994, 14 out of the 19 ISC projects were active(1). As of April 1992, according to an Oil & Gas Journal report, the incre-mental daily oil production from ISC was approximately 4,700 BOPD (from 8 projects) in the USA, while the same figure was 8,000 BOPD (from 10 projects) in the former Soviet Union, 7,300 BOPD (from three projects) in Canada and 12,000 BOPD (from five projects) in Romania. The 1992 world daily oil production from ISC was about 32,000 BOPD (5,100 m3) from 26 reported projects. The number of projects reported included, not only com-mercial, but also some semi-industrial projects.
In 1994, out of the listed projects, nine were started from the up-permost part of the structure, and at least seven have been operated using the line drive well configuration.
The most important parameters, indicative of economic effi-ciency, are air/(incremental) oil ratio (AOR) and injection pres-sure. For the same value of AOR, lower injection pressure means better economics. For heavy oil (viscosity higher than 50 mPa•s) recovery by ISC, an AOR in the range of 1,000 – 4,500 sm3/m3 (6,000 to 25,000 scf/bbl) for injection pressures of 1.4 – 14 mPa (200 to 2,000 psi) was recorded for 14 active ISC processes in 1992.
Over the last few years, the number of field pilots involving conventional ISC have been very low. Today, to our best knowl-edge, there are only three field tests(2-4): one in the Kerxing Field, Nemangu State in China and two more in the Gujarat State in India which are the Lanwa and Bechraji pilots.
Different types of well flooding networks may be used for ISC applications. ISC can be applied either in well patterns or in a line drive well configuration. The first system could be applied as con-tiguous patterns or isolated patterns, with the location of the pattern being upstructure or downstructure. So far, all these configurations were tried, but most applications use contiguous patterns and pe-ripheral line drive configurations.
The line drive should only be applied starting from the upper part of the reservoir. For this reason, it is extremely important to place the pilot upstructure. This way, after the test is finished, one can have both options of developing a commercial phase; that is, using either line drive or patterns.
ISC, in principle, is a gas injection, which has additional ben-eficial effects associated with the propagation of the heat wave generated by the ISC front. Like conventional peripheral gas dis-placement, it is normal to start the process upstructure.
The goal of this paper is to present the current status of conven-tional ISC applications to heavy oil reservoirs. The commercial application of air injection for oil recovery from high temperature, light oil reservoirs(1) is not covered here.
TAble 1: Commercial In Situ Combustion (ISC) projects: reservoir properties.
Initial Res. Pressure/ Reserve Connate Oil Oil Pressure Res. Gross Pay/ Water Saturation Visc. Oil at Start Field, Dip Depth Temp. Net Pay Satur. at Start Perm. at Tr Gravity of ISC OOIPCountry Formation Degrees (ft) (Tr) ˚F (ft) Porosity (%) (%) (mD) (cp) (˚API) (psi) (MMbbl)
Suplacu de S* 5 – 8 115 – 720 65 27 – 290/20 – 89 32 15 <85 5,000 – 7,000 2,000 16 140/80 310 Barcau, romania
Balol, India S** 4 – 7 3,280 158 10 – 95/9 – 50 28 30 70 3,000 – 8,000 100 – 450 16*** 1,450/1,450 128Santhal, India SS 3 – 5 3,280 158 16 – 195/9 – 50 28 30 70 3,000 – 5,000 50 – 200 18*** 1,450/1,450 300Bellevue, SS 0 – 5 400 75 70+;30+/_ ; _ 32 27 73 650 676 19 /40 4.6+; 10.6+
Louisiana, uSA
S = sand; SS = sandstone.*unconsolidated.**Coal and carbonaceous material are present (as streaks) within the sand formation (approx. 10% vol).*** Sulphur content 0.14%.+ Lower sand and upper sand, respectively.
TAble 2: Commercial ISC projects: results.
Daily Oil Current expected Start Date Inj. No. of No. of Prod. by Water O2 Air/Oil OilField, (of comm. Press. Inj. Prod. ISC Cut Utilization Ratio RecoveryCountry oper.) (psi) Wells Wells (Bbl/day) (%) (%) (Scf/bbl) (%)
Suplacu de Barcau, romania 1971 150 – 200 111+ 736+ 9,000++ 82 95 14,000 52Balol, India 1997 1,300 – 1,600 30 75 4,400 60 >95 5,600 38Santhal, India 1997 1,200 – 1,500 30 105 4,000 60 >95 5,600 36Bellevue, Louisiana, uSA 1970 60 15 90 300 90 80 15,000 60
* The ISC piloting starting 3 – 7 years earlier than this date (7 years for Suplacu, Balol and Santhal and 4 years for Bellevue).+ At any time, there are also 24 production wells under cyclic steam stimulation (CSS).++ It includes the contribution of CSS, estimated between 18% and 25% of the daily oil production.
The first three projects are operated using a peripheral line drive starting from the uppermost part of the reservoir and going downdip. While the Suplacu de Barcau project occurs in a typ-ical solution gas drive, shallow heavy oil reservoir, the Balol and Santhal projects are applied successfully in deeper reservoirs, having strong lateral water drive.
The BSOC Bellevue ISC project has been in operation for more than 34 years. It is a dry ISC process, and it has been con-ducted in patterns. Currently, it has 15 air injectors and 90 pro-duction wells.
November 2007, Volume 46, No. 11 3
Current Active ISC Commercial ProjectsThe commercial dry ISC project at Suplacu de Barcau, Romania
is the largest project of its kind, and it has been in operation for more than 34 years. The Balol and Santhal projects in India have been in operation for more than seven years, and have been applied in a wet mode. Currently, combined, all these three projects pro-duce approximately 2,300 m3/day (15,860 bbl/day). Additionally, the project operated by Bayou State Oil Corporation (BSOC) in Bellevue, Louisiana, USA produces 51 m3/day (320 bbl/day).
The first three projects are operated using a peripheral line drive starting from the uppermost part of the reservoir and going downdip. While the Suplacu de Barcau project occurs in a typical solution gas drive, shallow heavy oil reservoir, the Balol and San-thal projects are applied successfully in deeper reservoirs, having strong lateral water drive.
The BSOC Bellevue dry ISC project has been in operation for more than 34 years, and it has been conducted in patterns. Cur-rently, it has 15 air injectors and 90 production wells.
In the presentation of these projects, the focus is on the main characteristics of the process, and what have been the main op-erational problems. The main properties of the four reservoirs ex-ploited by ISC are presented in Table 1, while Table 2 provides the main results.
Suplacu de Barcau projectThe Suplacu de Barcau project uses a dry ISC process con-
ducted at low pressure (less than 1.4 MPa or 200 psi) in a very shallow reservoir (less than 180 m or 600 ft) using a small well spacing (50 to 100 m distance between wells). The oil viscosity is relatively high, around 2,000 mPa•s. The operation uses a periph-eral direct line drive.
The reservoir is located in the Northwestern part of Romania, 70 km from the town of Oradea. It is a Panonian formation, and it was formed by the moulding of the underlying crystalline basement. It represents an East-West oriented anticline upfold, axially faulted by the major fault of Suplacu de Barcau, limiting the field to the South and East (see Figure 1). The length of the monocline is ap-proximately 15 km. To the North and West, the field borders upon a weak aquifer. Both depth and thickness increase from the East to West and the North to South (Table 1). The depth is in the range of 35 m (115 ft) to 200 m (660 ft) and the thickness is in the range of 4 m (14 ft) to 24 m (80 ft).
The reservoir was put into production in 1960, the solution gas drive being the main mechanism; an ultimate oil recovery of 9% was predicted. Initial oil rates were in the range of 2 to 5 m3/day/well (12 – 36 bbl/day) but they decreased very quickly to 0.3 to 1 m3/day/well (2 to 6 bbl/day/well).
During 1963 to 1970, both the ISC and steamdrive methods were tested at the upper part of the structure in a single 0.5 ha pattern. A semi-commercial operation consisting of six contiguous patterns of 2 – 4 ha were used for both methods(5). Based on the semi-commercial performance, the decision to use ISC for commercial
exploitation was taken in 1970. At the same time, it was agreed that steam injection will be used permanently in a cyclic steam stimulation (CSS) mode in order to prepare (slight pre-heating) the production wells located close to the ISC front. Also, the de-cision to convert the pattern exploitation to line drive exploitation was made. The decision to sweep the reservoir starting from the uppermost part of reservoir was also supported by two separately operated experimental ISC patterns located at the middle and at the lowest part (close to the water-oil contact) of the structure, re-spectively. These pilots were operated for more than 4 to 5 years and they showed that the control and the efficiency of the process are less when the pattern is not located on the upper part of the structure(6, 7).
Since 1979, the linear ISC front has been propagated downstruc-ture, parallel to the isobaths. At the same time, starting in 1986, the process was expanded in new areas of the Western part of the res-ervoir. The current position of the ISC front is shown in Figure 1. The air injection wells are included in an East-West line of more than 10 km (6 miles) and the distance between two adjacent wells within a row is 50 – 75 m (152.5 – 229 ft). Based on the real perfor-mance of the wells, for the zone already processed by ISC, an (ulti-mate) oil recovery of 55% was calculated. Based on that amount, it was estimated that the expected ultimate oil recovery for the entire pool would be higher than 50%. More details on the calculations procedure are presented elsewhere(8).
In 1983, a second linear ISC front, parallel to the main one but located (a little bit) downstructure, was opened in the middle of the structure in the Eastern part of the reservoir (which is wider), as shown in Figure 1. The operation of two parallel ISC fronts has been challenging, mainly due to the reduction of the main, updip ISC front propagation velocity and to the downgrading of the whole perform-ance. In 1996, the second ISC front was abandoned. At the same time, with limited success, many trials have been conducted to put the former injection wells into production(9).
Since 1998, both air injection rates and the capacity of steam used for CSS have been reduced. Following this, total oil production re-mained constant for the first six months, but afterwards, a decline of oil production was noticed. The performance of the commercial ISC project is shown in Figure 2. Over time, the water cut has increased up to 82%, which is the current value. This increase in water cut is explained by the very extended nature of the water-oil contact and the proximity of a good number of producers to the current oil/water contact.
It can be seen that maximum oil production was recorded in the period 1985 – 1991, when the total air injection rate was at a max- – 1991, when the total air injection rate was at a max-1991, when the total air injection rate was at a max-imum (see Figure 2). AOR has had a tendency to increase, and today it is in the range of 2,600 – 3,200 sm3/m3 of incremental oil. As CSS has been continuously applied in parallel with the ISC process, it was estimated (based on the real performance of CSS stimulated and non-stimulated groups of producers) that its contribution was as much as 18% for the Eastern part of the project, and as much as 25% for the Western part where the net pay thickness is significantly higher.
Air injection wells
Combustion front
Initial water/oil contact
Influenced zone
N
Burned out area
Suplacu de Barcau Fault
FIGURE 1: The position of the in situ combustion front at Suplacu de Barcau, as of July 1st, 2004.
010,00020,00030,00040,00050,00060,000
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/73
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/76
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707
/78
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911
/80
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/83
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407
/85
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611
/87
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903
/90
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107
/92
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/94
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/97
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807
/99
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/01
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/04
Time (months)
020,00040,00060,00080,000
100,000120,000140,000
01/6
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/62
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/64
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/66
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/68
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Time (months)
01,0002,0003,0004,0005,0006,0007,000
Injected air Air oil ratio
Air
Inje
cted
(M S
m3 /
mo
nth)
Oil
Pro
d.,
(to
nne/
mo
nth)
Air-O
il Ratio
(Sm
3/mo
nth)
FIGURE 2: Performance of the Suplacu de Barcau ISC Project.
4 Journal of Canadian petroleum Technology
This project has been one of the best measured ISC projects in the world(6-11). Hundreds of bottomhole temperature (BHT) profiles have been taken at the observation and production wells and some of them saw very high peak temperatures (around 600°C) located in the upper part of the layer, clearly indicating the segregated na-ture of the ISC process. Actually, some of the producers have ex-perienced burnings, as approximately 15% of the producers have been replaced with new wells. Also, a large number (12) of coring wells in the already burned areas were drilled and it was observed that 5 – 7 m were burned out near the top, with 7 – 10 m of the rock underneath, unburned but heated by the ISC front.
For reasons related to the safety of workover operations, a re-usable special drilling mud was developed at the hot producers to kill these ‘hot wells’ which had temperatures in the range of 80 to 250°C. This fluid ensures equilibrium in the well, avoids blockage of the formation and presents rheologic-colloidal characteristics proper to the specified temperature(5).
The ISC application has led to the increase of concentration in natural emulgators in the produced oil, such as asphaltene, resins, naphtenic acids and finely dispersed solid particles, leading to the formation of very tough, rebellious emulsions. Special fluidizers have been administered at the bottomhole, or even into the forma-tion, to break these emulsions. As far as the dehydration and de-salting of the crude oil is concerned, a patented, special technology for the thermal-chemical treatment, with a final stripping step, was developed(9).
A major challenge was the leakage to the surface of some com-bustion gases through some kinds of mud and steam volcanos, which appeared high on the structure and have accompanied ISC commercial exploitation, almost since its beginning(10). This es-caping gas can be related to both the very small depth of the res-ervoir (just 35 m or 115 ft at the upper part) and to the improper sealing of some old producers.
Based on the present development of the process, it is estimated that in order for the ISC front to cover the entire surface of the pool (up to the initial oil/water contact), 20 more years are necessary (see Figure 1). This means a continuous ISC commercial operation of more than 50 years.
Santhal and Balol projectsThe Santhal and Balol projects use wet ISC processes conducted
at high pressure (greater than 10.3 MPa or 1,500 psi) in a reservoir (approximately 1,000 m or 3,000 ft) producing under a strong lat-eral water drive. The oil viscosity is medium, between 50 and 200 mPa•s for Santhal and between 200 mPa•s and 1,000 mPa•s for Balol. The operation uses a peripheral direct line drive, which is sometimes direct, and sometimes staggered.
The Santhal and Balol reservoirs belong to the Heavy Oil Belt lo-cated in the Northern area of the Gujarat State in West India. The oil structure was discovered in 1971, and industrial oil production began in 1974 in Santhal and in 1985 in Balol(11).
The structure consists of a combined structural-stratigraphic trap with its axis NNW-SSE. The oil layer dips in the W-E direction. The oil accumulation is limited updip by a pinch-out line and downdip by a water-oil contact (see Figure 3 ). The oil was found in the Kalol pay zone of the Eocene age. The Kalol zone contains three oil-bearing sands: KS-I, KS-II and KS-III. The upper sand, KS-I, has the largest area extent; the areal extent of the sand unit decreases from the top sand to the bottom sand. The three sands seem to form a single hy-drodynamical unit, as the initial oil-water contacts are the same and, in approximately 40% of area, the sands are in communication due to commingled production in the exploitation wells.
The overburden is formed of a 3 – 7 m thick shale. The pay section is unconsolidated sand with interbedded shale, carbonaceous shale and coal. The unique feature of the reservoir is that coal and carbo-naceous material are present in the adjacent shale formation and/or in the oil formation. In the oil layer, coal is present both as dispersed coal (black particles and centimetric laminations) and as coal and car-bonaceous material streaks with a horizontal extension from a few metres up to the distance between two wells. The thickness of the coal streak is usually greater outside the pay zone, varying from 0.2 m in-side the pay zone, up to a few metres outside the pay zone.
The main properties of these reservoirs are provided in Table 1. The oil recovery mechanism is the natural edge water drive under the condition of a very unfavourable mobility ratio. As of 1991, be-fore the ISC commercial application, the water cut was 60 – 75% for both Balol and Santhal. Oil production was in the range of 3 – 6 m3/day/well for Balol and 5 – 10 m3/day/well for Santhal. For both Santhal and Balol, the static pressure has been almost constant up to the present. This confirms that there is a strong aquifer and oil is still above the bubble point pressure. The behaviour of the reservoir under primary conditions is better known for the Santhal Field where, as of 1991, there was almost 17 years of past performance. Out of 93 active oil wells, 56 were producing from KS-I, 3 were producing from KS-II and the balance were producing from two or three layers together. An almost equal total number of wells were drilled in the Balol Field.
Originally, oil was produced by natural flow. Subsequently, sucker rod pumps were installed at the wells. Presently, the majority of the wells are on a pump, while some wells are self-flowing due to a heat effect.
No significant problems of sand influx into the production wells have been encountered. In general, the gravel packing of the pro-ducers has worked properly.
ISC was tested starting in 1990 in Balol. Initially, one 2.2 ha inverted five-spot pattern was used. This was enlarged to 9 ha by drilling four new wells(12). Then, a second ISC pattern was added to the North of the initial one (see Figure 3). By 1995 – 1996, based on the favourable performance of these two patterns, a decision to use ISC for commercial exploitation of Balol was taken; this started in 1997, and from the very beginning a peripheral updip line drive was adopted.
In Santhal, the ISC process was tested for a few years in an in-verted five-spot pattern, located in the Northern part of the field (Santhal Phase-I). The initial design adopted for the commercial op-eration was ‘patterns exploration.’ Later on, based on the Santhal Phase-I and the experience from the adjacent Balol ISC exploitation, the initial decision was reversed in favour of the peripheral updip line drive, which is now in operation. The commercial exploitation also started in 1997.
FIGURE 3: Santhal-Balol-Lanwa Field—Schematic map showing location of the experimental in situ combustion patterns.
November 2007, Volume 46, No. 11 5
Both in Balol and Santhal, wet ISC was tested and then applied commercially(13-14). The water-air ratio has been between 0.001 and 0.002 m3/sm3, and the air and water injection has been done in an alternative way (non-simultaneous injection). The wet combustion might have helped in moderating the high peak temperatures in the ISC front, leading to the reduction of H2S in the combustion gases. The percentage of H2S in the combustion gases has been in the range of 100 – 1,500 ppm, with spikes of up to 4,000 ppm.
Currently, the air/water injection wells are spread in a North-South line of more than 12 km (7 miles) in Balol and of more than 4.6 km (2.9 miles) in Santhal. Given the relatively high reservoir temperature (70°C) and pressure, spontaneous ignition is used for the initiation of the ISC process in some of the wells of the commer-cial operation.
The increase over time of oil production due to the expansion of the Balol ISC project is shown in Figure 4a, while the same for the Santhal project is shown in Figure 4b. Figure 5 shows the typical performance of a production well in Balol, which displayed a dra-matic reduction of the water cut (from 75% to under 5%) as the ISC was displacing oil and pushing it downdip towards the well. Simi-larly, producers in Santhal would display the same spectacular re-duction of the water cut. This shows, in a very convincing way, that ISC is an efficient method for the exploitation of heavy oil in the presence of a strong lateral water drive; the water is pushed back into the aquifer. The main results of these projects are provided in Table 2. It can be seen that the air/oil ratio has a favourable value of 1,000 sm3/m3 (5,600 scf/bbl) for both projects.
Analysis of the properties of the produced oil did not show any consistent viscosity reduction over a long period of time. As in other projects, sometimes this reduction appears, and sometimes it does not; there is no consistency.
Initially, both in the Balol and Santhal projects, only the upper KS-I layer was considered for ISC application. Later on, in the San-thal project, KS-II was also considered for ISC application. Pres-ently, in the Santhal project, the ISC front is propagated in KS-I and KS-II, although the generated combustion gases have been noticed in the updip wells completed in the underlying KS-III formation.
This shows that a shale separation of around 1.5 m is probably not enough to assure hydrodynamic separation in the case of the ISC application.
In order to solve the pollution problem caused by H2S, SO2 and hydrocarbon gases, the produced combustion gases are flared in tall flare stacks equipped with outside make-up gas and electronic ig-niters. It should be mentioned that, unlike almost all other commer-cial ISC projects worldwide which have some 1-2% hydrocarbon gases in the produced combustion gases, the percentage is higher in this case; 5 – 6%. This helps in reducing the amount of make-up gas for flaring.
BSoC Bellevue projectThe BSOC Bellevue project uses a dry ISC process conducted at
very low pressure (less than 0.42 MPa or 60 psi) in a shallow res-ervoir (120 m or 400 ft) of relatively low permeability (700 mD) and high heterogeneity. It contains two layers which are operated separately. The oil viscosity is 676 mPa•s. The operation uses a pattern system.
The Bellevue Field is located in the Northwest corner of Loui-siana, USA, in Bossier Parish. This field has accommodated the big-gest in situ combustion (ISC) operation in the USA. Therefore, more information and details can be found in certain textbooks on thermal oil recovery(15).
The reservoir, which is a dome structure, was discovered in 1921, and its oil production peaked in 1923, at 1,115 m3/day (7,000 bbl/day) with initial oil rates up to 159 m3/day/well (1,000 bbl/day/well). In 1963, Getty Oil initiated an ISC pilot in a 1 ha (2.5 acre) inverted 9-spot pattern, and based on its successful operation, more experi-mental patterns were added.
Later on, in the period 1970 – 1971, both Cities Service Oil (CSO) and Bayou State Oil Corporation (BSOC) began an ISC experi-mental program. CSO tested ISC within four contiguous patterns. The ISC areas operated by these operators are shown in Figure 6. Both the Getty and CSO projects were operated as wet combustion processes and they were expanded a few times up to 1978. In 1982,
FIGURE 4: Oil production evolution: a) Balol ISC Project; b) Santhal ISC Project.
0
20
40
60
80
100
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005
0
20
40
60
80
100
Ql (
m3 /
d),
Qo
(tp
d) -
->
Ql (m3/d) Qo (tpd) WC (%)
Water-C
ut(%) -->
FIGURE 5: Production performance of a typical ISC-affected production well in Balol. Legend: Ql = total liquid; Qo = oil production; WC = water cut.
FIGURE 6: Bellevue Field, Louisiana. The zones operated by in situ combustion by different companies.
FIGURE 7: Bellevue Field, west-east cross-section through the Wyche Lease of BSOC, operated by in situ combustion.
6 Journal of Canadian petroleum Technology
223 wells were involved in the Getty project with oil production of approximately 438 m3/day (2,750 bbl/day) at an air-oil ratio of 3,000 – 3,500 sm3/m3. The expected ultimate oil recovery was 60%(15). While Getty and CSO discontinued their ISC projects probably in the period 1984 – 1990, BSOC has continued to operate their project, anticipating ISC operations to continue for several more years. This project is the focus of our analysis.
The main properties of the reservoir are provided in Table 1. The producing zone is the upper Cretaceous Nacatosh, which con-sists of unconsolidated sand of considerable permeability varia-tions. The sand is crossed by faults and streaked with layers of sandy shale and fossilized lime. The sand is divided into three zones (Figure 7). The upper zone varies from 15.3 – 21.4 m (50 – 70 ft) in thickness, the middle zone varies from 3.1 – 6.2 m (10 – 20 ft) in thickness and the lower zone varies from 9.3 – 15.3 m (30 – 50 ft) in thickness. Only the upper and lower zones are pro- – 50 ft) in thickness. Only the upper and lower zones are pro-50 ft) in thickness. Only the upper and lower zones are pro-ductive (oil saturated). The middle zone consists of a lime layer, which seems to effectively separate the two oil layers. Figure 7 shows a W-E cross-section, which also shows the perforation depth for each well.
The ISC process was started by BSOC in 1970 in the lower sand with three inverted 7-spot patterns located in the middle of the structure (first phase). The average area of the pattern was 1 ha (2.5 acres). When the ISC testing was initiated, the oil recovery was 10%. Later on, starting in 1972, more patterns were added such that in 1978, there were 10 air injection (combustion) wells; all operating in the lower sand. In 1983, three patterns located at the Eastern edge (downdip) were ignited in the upper zone, starting the simultaneous ISC operation of lower and upper sand. Until 1986, wet ISC was tested in three patterns, but afterwards only dry ISC has been applied. In 1986, air injection was terminated in 6 low sand patterns, with continuous water injection in three of them for two years. Generally, the patterns have a small area, in the range of 0.6 – 1.2 ha/pattern (1.5 – 3 acres/pattern).
Today, there are 15 active air injection patterns in operation, of which 53 wells are producing combustion gases. Approximately 62.5% of the produced gases are measured. Several production wells produce gas, which is not measured, and a considerable amount of it migrates across lease boundaries. For all 15 air in-jectors, a total of 45,000 sm3/day (1.6 million scf/day) air is in-jected, for the production of 50 m3/day (320 bbls) of oil (air oil ratio = 15,000 scf/bbl). The average air injection rate per well is 9,000 sm3/day (300,000 scf/day) for an average pattern area of 1 ha (2.5 acres). BSOC has been able to operate (including ignition) the upper layer and the lower layer separately; an average of 5.5 m (18 ft) thickness of lime (separation) was enough to ensure sepa-rate and simultaneous operation.
The main results of the project are provided in Table 2. The water cut is extremely variable, but, in general, in the lower zone it is higher, being between 95% and 98%. Upper zone wells have water cuts between 90% and 96%.
The ignition is accomplished using electrical heaters. Recently, the practice of ignition operations have been improved by taking into account the relatively high heterogeneity of the reservoir. The improvements consists of injecting a higher amount of heat around the injector during ignition (including a slower increase in down-hole temperature) and then, immediately after ISC is initiated, in-creasing the air rate at a slower pace. This way, for the last three patterns where ISC was initiated, the oxygen utilization increased and the oil production performance improved. Generally for this process, where the maximum air injection rates are low, a per-centage of 1.3 – 2.5% oxygen in the combustion gases is noticed. The CO2 percentage is 15 – 17%.
From the bottomhole temperature profiles, a maximum temper-ature of 204°C (400°F) was recorded. Some new infill wells were used as coring wells (in the already burned area) and it was ob-served that 3 m (10 ft) of rock was burned out at the top, with 12 m (40 ft) of rock underneath that was unburned but heated by the ISC front. Before 1980, four production well burnouts were experienced. Also, four wells were drilled as replacements for older wells, which cratered. As a rule, up to 10% of the producers have been replaced with new wells. In drilling replacement wells,
the last improvement in technology is to drill them approximately 7 m (20 ft) laterally away from the damaged producer, run tem-perature surveys and then perforate 5 – 7 m (15 – 20 ft) below the high temperature point. This technique is associated with good producers, as far as combustion gases, moderate temperature and oil production performance are concerned.
The combustion gases, which contain some hydrogen sulphide, sulphur dioxide, oxygen and water vapour, combined with a tem-perature of 38 – 65°C (100 – 150°F), creates a very corrosive envi- – 65°C (100 – 150°F), creates a very corrosive envi-65°C (100 – 150°F), creates a very corrosive envi- – 150°F), creates a very corrosive envi-150°F), creates a very corrosive envi-ronment. Corrosion is not eliminated, but is somewhat controlled by downhole treatment with corrosion inhibitors and biocides.
Emulsion problems have been very troublesome. A combination of viscous crude with brine of low salt content, coke from the burn, fines and iron oxides produces a rebellious emulsion that is some-times difficult to treat. Several brands of emulsion breakers have been tried over the years. Occasionally, the nature of crude changes as the ISC front gets closer to the wellbore, and a new treatment has to be developed.
A full development of the ISC project for the upper sand across the lease is contemplated. This is to be conducted by using lower sand injectors, as they are shut-in after they have accomplished their mission. Lower sand will be plugged off and the wells will be perforated in the upper zone. Two more injection wells, where this operation is contemplated, will be used to expand the current ISC process underway in this upper layer.
lessons From the Commercial ISC Projects
A common feature of all four commercial operations was the overriding of the formation by the ISC front or, in other words, the segregated character of the process. This is a permanent feature of almost any conventional ISC process (using vertical wells) ap-plied to heavy oil, and it was seen both in the bottomhole tempera-ture profiles recorded in the observation and production wells, and from the coring wells drilled in the burned out zones. Prediction of the arrival of the ISC to a certain production well has not been pos-sible based on the composition change for gases and/or produced fluids. Only when the bottomhole temperature increases could the arrival be predicted. After interception by the ISC front, the pro-ducer usually shows a higher-than-normal oxygen percentage in the gas produced.
After analysing the oil viscosity impact on those four projects, it can be seen that for three projects where oil viscosity is less than 1,000 mPas, it is possible to operate the ISC process without the as-sistance of any cyclic steam stimulation (CSS) application. How-ever, for the Suplacu de Barcau project, where oil viscosity is around 2,000 mPas, CSS has been a necessity.
Although ISC has been operating for more than 50 years, the ef-fect of ignition operations on performance of the process itself has never been systematically investigated in the field as a pre-heating technique. However, in the BSOC Bellevue project, which is oper-ated in a relatively heterogeneous formation, it was demonstrated that the quality of ignition operation and the way the process is conducted immediately after ignition has an important impact for the global performance of the process.
In case of the Suplacu de Barcau, Balol and Santhal projects, al-though the ISC process takes advantage of gravity by initiating the ISC front updip and propagating it downdip (peripheral line drive), there are still some channelling phenomena and the ultimate oil re-covery is in the range of only 40 – 50% OOIP due to a relatively low volumetric sweep.
The Balol and Santhal projects clearly demonstrated that the ap-plication of the ISC process in a peripheral line drive for strong lateral water drive reservoirs can be very beneficial as the edge water is kept under control and the water cut of the production wells could be decreased significantly. In addition, these wet ISC processes showed that, although the ultimate oil recovery may be slightly lower, larger distances between wells could be adopted, such as 300 m (980 ft) compared to 50 – 100 m (152 – 305 ft), for Suplacu de Barcau and BSOC Bellevue.
November 2007, Volume 46, No. 11 7
Generally, for experimental, semi- or commercial ISC operations, the AOR is in the range of 1,000 – 4,500 sm3/m3 (6,000 – 25,000 scf/bbl). Although the Suplacu de Barcau and BSOC Bellevue projects currently have an AOR in the range of 2,600 – 3,500 sm3/m3, which is on the high side, they are still economical, as the injection pressure in these projects are very low 0.42 – 1.4 MPa (60 – 200 psi).
It was shown that the simultaneous operation of several layers was possible where spontaneous ignition could easily be obtained. The BSOC Bellevue project is unique due to the fact that it is the only commercial ISC project ever operated where the separate but simultaneous ISC operation of two oil sands in a stack has been possible, even though spontaneous ignition has not been achieved. A lime layer of 5.5 m (18 ft) was enough to ensure this separate (and simultaneous) operation.
ConclusionCurrently, there are four active commercial ISC projects world-
wide, which have been in progress for a long period. The general trend has been of a decrease in both the number of projects and the total oil production from commercial operations. The all-time max-imum oil production from commercial ISC projects has been 5,100 m3/day (32,000 bbl/day) in 1992, and it has decreased steadily to ap-proximately 2,400 m3/day (15,000 bbl/day) as of 2004.
Three of the current commercial ISC projects are operated using line drive well configuration, with a linear ISC front generated at the uppermost zone of the reservoir and being propagated towards the lower zone of the reservoir. The fourth commercial operation is a smaller one, and it is conducted in patterns.
Irrespective of what system, line drive or patterns, is to be ad-opted, the ISC pilot should be located at the upper part of the res-ervoir. When designing an ISC exploitation, one should compare the pattern system with the peripheral line drive system, as far as the advantages and disadvantages in operation and evaluation are concerned.
All current ISC commercial operations are conventional ISC ap-plications and these are operated in a long-distance oil displace-ment mode, which means that the displaced oil flows through the cold zone before it is produced. New ISC processes have been re-cently proposed and they are operated in a short-distance displace-ment mode in relation with the use of horizontal wells. One such new process is now under field testing.
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10. CARCOANA, A., Results and Difficulties of the World’s Largest In-Situ Combustion Process: Suplacu de Barcau Field, Romania; paper SPE 20248 presented at the SPE/DOE Enhanced Oil Recovery Sym-posium, Tulsa, OK, 22-25 April 1990.
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14. CHATTOPADHYAY, S.K., RAM, B., BHATTACHARYA, R.N. and DAS, T.K., Enhanced Oil Recovery by In Situ Combustion Process in Santhal Field of Cambay Basin, Mehsana, Gujarat, India�A Case Study; paper SPE 89451 presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, OK, 17-21 April 2004.
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Provenance�Original Petroleum Society manuscript, Current Status of the Commercial In Situ Combustion Projects Worldwide (2005-022GE), first presented at the 6th Canadian International Petroleum Conference the 56th Annual Technical Meeting of the Petroleum Society), June 7-9, 2005, in Calgary, Alberta. Abstract submitted for review September 28, 2004; ed-itorial comments sent to the author(s) August 31, 2005; revised manuscript received July 10, 2007; paper approved for pre-press July 10, 2007; final approval <Approved>.