Jeff Ventura
Maxus Energy Corp.
Dallas
Atmawan D. Temansja
Maxus Southeast Sumatra Inc.
Jakarta
In an offshore Southeast Sumatra contract area, resizing downhole pumps increased withdrawal rates from 36 of 37 worked-over wells. These greater fluid producing rates, according to decline curve analysis, will substantially add to the recoverable oil reserves.
The work increased an average well's oil production rate by 183 bo/d and added 183,000 bbl/well to recoverable oil reserves without materially affecting water cut. The cost of the reserve additions was $0.37/bbl. No loss in ultimate recovery was indicated for any of the wells.
CONTRACT AREA
The Southeast Sumatra contract area is located offshore in the Java Sea, 80-100 miles north of Jakarta. Two prolific sedimentary basins, the Sunda and Asri, are in the block (Fig. 1).
The block's production sharing contract was signed on Sept. 6, 1968. The first discovery well, Cinta-1, was drilled in August 1970 in the south-central part of the Sunda basin. Production commenced from the Cinta field in September 1971.
In the Asri basin, the first discovery was made in October 1987 by the Intan-1 well and production followed in June 1989.
At present, the Southeast Sumatra contract area produces 250,000 bo/d from 220 wells located in 18 fields. As of May 1, 1991, cumulative oil production from the fields was 570 million bbl.
Of the 250,000 bo/d production, the more recent Asri basin fields account for approximately 200,000 bo/d. The older Sunda basin fields produce the remaining 50,000 bo/d. All wells in both basins are produced with electric submersible pumps (ESPs).
SUNDA BASIN
The Sunda basin contains 15 fields. Nine fields produce from continental sandstone reservoirs of the Talang Akar formation. Production from the other six fields is from the overlying marine carbonate Batu Raja reservoirs.
The overall basin structure is that of a series of mainly north-south rifts. These rifts are propagated stepwise towards the northeast into the Sunda land craton.
Fig. 2 shows that subsidence along the rifts produced a series of half-grabens. The largest graben (Seribu) deepens eastward where a large block of Cretaceous continental crust foundered against the northwest edge of the Seribu platform.
Subsidence associated with rifting was accompanied by the deposition of up to 9,000 ft of continental clastics in six separate half-graben centers of deposition.
The continental sequence comprises alluvial fan, lacustrine, fluviatile, and paludal deposits of the Banuwati and Talang Akar formations. These formations range in age from early Oligocene to early Miocene (Fig. 3).
The oil reserves in the basin are contained within two widespread reservoir systems: fluviatile sandstones (Talang Akar formation) and reef-associated carbonates (Batu Raja formation).
The sandstone reservoirs are developed best at the basin margin where the reservoirs are optimally located for hydrocarbon migration and trapping. Reservoir facies in the transgressive carbonate system are restricted to the paleohighs, which were shallow and intermittently emergent. Three source systems have been recognized in the nonmarine section of the Sunda basin. Lacustrine and paludal shale, and coal source rocks are distributed vertically throughout the generative oil window within the Sunda basin.
Migration pathways are the basement surface zone, alluvial fans, fluviatile sandstone, transgressive carbonates, and faults. The reservoir facies lie beneath, within, and above the source systems and provide short migration routes from the generative areas to the trap association at the basin margins.1
BATU RAJA
The carbonates and claystones of the Batu Raja formation overlie the Talang Akar formation, conformably in most places, and have been divided into upper, middle, and lower members. They are of marine origin and are early Miocene in age.
The upper limestone unit, usually referred to as the carbonate buildup, is thinner than the lower unit and ranges in thickness from 100 to 300 ft. In general, the carbonate buildup is made up of several thinner, lenticular carbonate buildups.
The Batu Raja carbonate is conformably overlain by the Gumai formation marine transgressive claystone, which is also of early Miocene age. The marine transgression which reached its peak in Gumai time is commonly referred to as the Gumai shale that forms the seal to the Batu Raja carbonate oil fields within the Sunda basin.
The Batu Raja fields produce at depths ranging from 2,300 to 4,700 ft. Since first production in September 1971 through April 1991, the cumulative oil production from the Batu Raja carbonates is approximately 216 million bbl. Approximately 156 million bbl, or 72% of the total Batu Raja oil production, is from the Rama and Krisna fields. The permeability of the Batu Raja in both fields is excellent and averages about 4.5 darcies.
TALANG AKAR
The Talang Akar formation has been divided into the lower, fluviatile Zelda member and the fluviatile-paralic Gita member. The Zelda member was probably deposited during late Oligocene time. The fluviatile-paralic Gita member was deposited during late Oligocene to early Miocene time, which is characterized by coalbeds at the end of its deposition.
In general, the Talang Akar formation consists of sandstone, claystones/shales, and coalbeds. Claystones and shales are the source for the hydrocarbons in the Sunda basin. Coals interbedded within the fluviatile sequences are likely to have generated oil, but they are not abundant.
Talang Akar fields produce at depths from 3,200 to 7,000 ft. Through April 1991, cumulative production from the Talang Akar sandstone reservoirs is 354 million bbl, including recent production from the Intan and Widuri fields in the Asri basin.
In general, the permeabilities of the fields that produce from the Talang Akar formation range from 1 to 10 darcies. The main exceptions are the Farida, Zelda, and Sundari fields which have permeabilities of 0.12, 0.05 and 0.13 darcies, respectively. These three fields account for 19% of the Talang Akar production to date.
PUMP RESIZING
From 1988 to 1990, 44 pumps were resized in 37 wells located in nine fields in the Sunda basin. The object was to increase the fluid withdrawal rates from the wells and thereby increase their oil production rates.
For each well, the following three plots were constructed:
- Total fluid rate, oil rate, water cut, and gas/oil ratio vs. time (rate vs. time)
- Oil cut vs. cumulative oil production (cut vs. cumulative)
- Oil rate vs. cumulative oil production (rate vs. cumulative).
All three plots were then analyzed before and after the pump changes to determine the net effect of the pump change in regard to changes in oil rates and reserves. In addition, any changes in water cut and gas/oil ratio were analyzed. In offset wells there was no evidence of any change in the performance as a result of increasing production rates.
For the purpose of extrapolating the rate vs. time and rate vs. cumulative plots, an economic limit of 50 bo/d was used.
The abandonment oil cut for the cut vs. cumulative plot was calculated by dividing 50 bo/d by the total fluid production rate at abandonment. This assumes that incremental water treating and disposal costs are relatively insignificant, which in fact is the case in Southeast Sumatra.
The results of the pump resizing program are listed in Table 1. The net effect is that for an investment of $3.0 million, the producing rate of these wells increased an incremental 8,062 bo/d. Also, the recoverable oil reserves from these wells increased by 6.41 million bbl.
This reserve increase is a conservative value because nine of the resizings are excluded. The reserves for these nine jobs were not quantifiable at this time because of one or more of the following reasons:
- The oil cut from the well was increasing with time.
- The well's oil producing rate had no decline.
- The pump resizing was too recent and the well's production had not yet established a trend.
The average well from this program showed an incremental increase in rate of 183 bo/d and an incremental increase in oil reserves of 183,000 bbl.
The average cost of a pump resizing was $68,000. Therefore, this program added oil reserves at a cost of $0.37/bbl. The incremental cost of the oil reserve additions is much less than $0.37/bbl because the majority of the resizings were done during the course of normal maintenance.
Table 2 lists the detailed data from which Table 1 was created. The range of oil reserve change shown on Table 2 is from 0 to 1.28 million bbl/well. Therefore, increasing the withdrawal rates did not adversely affect the ultimate recovery of any well.
Six of the 44 pump resizings (14%) were unsuccessful in that they neither increased oil rate or reserves. Two of the six jobs were unsuccessful because the wells were already pumped off. The other four were unsuccessful because of increased water cuts.
Four of the six pump resizings which were unsuccessful had a negative rate change. Despite this negative rate change, the wells' ultimate recovery appears to be unaffected. The decline rates of these wells did not change and the producing rates eventually recovered to the original trends.
Considering all 44 pump resizings, there was no noticeable difference in the performance of the wells which produce from the Batu Raja carbonates vs. Talang Akar sandstones.
The wells, Karmila A-2, Cinta E-4, Cinta C-3, and Krisna A-9, illustrate the typical analysis and performances of the wells that were part of this program.
KARMILA A-2
Fig. 4a is a rate-vs.-time plot of the Karmila A-2 well. The total fluid withdrawal rate from this well was approximately 6,550 bbl of fluid/day since the well began producing in 1983 until May 1988. During that time, the oil producing rate declined from an initial rate of about 6,550 to 1,769 bo/d as the water cut increased from 0 to 73%.
During May 1988, the well was gravel packed and a higher capacity ESP installed. Subsequently, the fluid withdrawal rate increased from 6,550 to 13,300 b/d.
The net result was that the oil rate increased from 1,769 to 3,119 bo/d, which is an increase of 1,350 bo/d. Using decline curve analysis (Fig. 4a), the net remaining reserves from this well increased by 1.3 million bbl oil.
Fig. 4b plots oil cut vs. cumulative oil production for the Karmila A-2. Assuming a 50 bo/d economic limit and a fluid withdrawal rate of 6,550 b/d, the oil cut at abandonment for this well would be 0.8%. Assuming the same economic limit, but at a fluid withdrawal rate of 13,300 b/d, the oil cut at abandonment decreases to 0.4%.
From Fig. 4b, the net result of decreasing the oil cut at abandonment from 0.8 to 0.4% is an increase of oil reserves of 1.28 million bbl.
Fig. 4c, which is a rate vs. cumulative plot, also shows that the oil reserves were increased by 1.28 million bbl. This is in good agreement with the incremental reserve gain calculated from the rate vs. time plot.
Fig. 4b also shows that there is little change in the trend of oil cut vs. cumulative oil production after the fluid withdrawal rate was increased. This is significant in that one of the concerns of increasing the withdrawal rate was that there might be an increased tendency to cone water.
However, because this well was already producing at a rate well in excess of its critical coning rate, little change in the trend of oil cut vs. cumulative oil production should have been expected. In the total program the average water cut showed little change, increasing from 83 to 84% (Table 2).
CINTA E-4
The Cinta E-4 is a well where the water cut increased significantly when the fluid withdrawal was increased. In December 1989, the fluid withdrawal rate from this well was increased from 1,658 to 4,400 b/d by changing the ESP (Fig. 5a). The water cut from this well quickly increased from 58 to 80%.
The most likely explanation for this water cut behavior is related to commingling multiple zones within the well.
Based on recent drilling and pressure testing, a significant pressure difference exists between the various zones. It is possible that a lower pressured, higher water cut zone was not contributing at the higher producing bottom hole pressure.
Placing a higher volume pump into the well created a lower producing bottom hole pressure which allowed the low-pressure zone to feed in. It is significant to note that despite the increased water cut, the well produced about 900 bo/d vs. 700 bo/d prior to the resizing. However, to optimize production from this well, an attempt should be made to isolate the high water cut zone.
The effect of changing the withdrawal rate on the well's reserves is not yet quantifiable. The graphs in Fig. 5 show essentially no decline before or after the pump change.
CINTA C-3
Well Cinta C-3 shows a trend in oil cut vs. time that has responded favorably after the well's total fluid withdrawal rate was increased.
In May 1988, a higher capacity ESP was installed. The total fluid withdrawal rate from the well increased from 3,115 to 4,005 b/d.
After the production rate increased, the trend in oil cut vs. cumulative oil production has flattened (Fig. 6a). Assuming that the prepump change trend returns, the incremental oil reserve increase as a result of this flattening would be 560,000 bbl.
In addition to the reserve increase described above, the ultimate recovery also increased because the abandonment oil cut was decreased. Increasing the withdrawal rate from the Cinta C3 decreased its abandonment oil cut from 1.6 to 1.2%. As a result, oil reserves increased by 520,000 bbl.
Combining the two mechanisms, the ultimate oil recovery from this well was increased by 1.08 million bbl.
From the decline prior to the pump change and the rate after the pump change, the extrapolation of the rate vs. cumulative plot (Fig. 6b) indicates that the ultimate oil recovery from this well increased by 980,000 bbl. This increase is about 9% less than predicted by the cut vs. cumulative plot.
The projections in Fig. 6c, which is a rate-vs.-time plot, gives an oil reserve increase of 1.05 million bbl. This increase agrees well with cut-vs.-cumulative projection.
KRISNA A-9
The previous examples showed wells that were producing at commercial rates before pump resizing. The Krisna A-9 well differs because the well was producing at its economic limit prior to resizing its pump.
Prior to pump resizing, the well was producing fluid at a rate of 1,740 b/d with 35 bo/d, or a 98% water cut (Fig. 7).
In October 1988, a higher capacity ESP was installed in the well. The fluid production increased to 2,400 b/d. The oil rate was 71 b/d or a 97% water cut.
This well produced through to the end of 1990 until it had declined to a rate of 39 bo/d with a 98% water cut. During this period, the well produced 60,000 bbl of oil.
The cost of this pump resizing was $36,000; therefore, oil reserves were added at a cost of $0.60/bbl. Prior to this, the Krisna A-9 had produced 763,000 bbl of oil. The incremental oil production from the pump resizing increased recoverable reserves to 823,000 bbl of oil, or an 8% increase.
REASONS FOR INCREASES
There are several mechanisms which could have caused the reserve increases listed previously. Following is a brief description of the various mechanisms:
- Increasing fluid withdrawal rate causes the oil production rate to increase and the oil cut at abandonment to decrease. The net result is that the life of the field is extended, thereby causing an increase in ultimate recovery.
- Minimizing the producing bottom hole pressure prevents the backflow of fluids into lower pressured zones open to the well bore.
- Increased rate and decreased producing bottom hole pressure allows lower permeability and pressured pores to be swept and produced.2
- Increasing the number of pore volumes of water through the reservoir decreases residual oil saturation. Typically in water-wet rocks, residual oil saturation is seen after 1 1.5 pore volumes of displacing fluid throughput.
However, in oil wet and heterogeneous-wet rocks, residual oil saturation continues to decline after 100 and 1,000 pore volumes of displacing fluid throughput, respectively.3 Several fields in the Southeast Sumatra Block appear to be either oil wet or heterogeneous wet. Laboratory results of a Cinta core (Fig. 8) demonstrate that oil recovery continues to increase even after 32 pore volumes of water have been injected.
- Conceptual models for water-systems in which water is displacing oil have demonstrated that residual oil saturation is decreased by in-creasing the pressure gradient.4-6 For a particular core subjected to an oil displacement process, the interfacial tension confines residual oil in the pores. Theoretically, such oil may be made mobile by decreasing the interfacial forces or increasing the viscous forces (fluid flow rate, viscosity ratio).3
Laboratory studies have verified that such is possible depending upon the rock properties.7-12 In some of the studies, a very small increase in pressure gradient made the residual oil mobile even when capillary forces were relatively large. Although no such investigations have been made on heterogeneous-wet cores, evidence suggests that such oil can be made mobile at even lower pressure gradients.3
CONSIDERATIONS
Before increased withdrawal rates can be viewed as a viable method to increase net present value profit and reserves, several operational and reservoir considerations must be studied. First, a systems analysis should determine the capability for the candidate well to produce more fluid.
If so, then consideration should be given to the potential for higher withdrawal rates to cause:
- Sand production
- Coning
- Reservoir pressure maintenance problems.
If significant sand problems are anticipated, then gravel packing should be considered as a solution.
Coning is usually anticipated to be a problem when the off-take from a well is increased. In Southeast Sumatra, as well as in several other parts of the world, minimum economic production rates are well in excess of the critical flow rates predicted by coning models. Therefore, significant water production is inevitable.
Studies have shown that the ultimate oil recovery of reservoirs that are pressure maintained are, at worst, insensitive to rate.13 In fact, studies have shown that even with attendant higher water production, higher rates resulted in increased ultimate oil recovery as well as profit.2 3 13-17
A major constraint imposed upon the applicability of increasing withdrawal rates is pressure maintenance. Either the supporting aquifer must be able to sustain the higher off-take rates or injection is required.13 15 In Southeast Sumatra, several of the reservoirs have strong water drives. In certain fields, such as Rama and Krisna, water injection has been required.
In addition to the considerations listed above, sufficient capacity must exist in the facilities and pipelines so that the larger volume of fluid can be properly handled. If it does not exist, then the system must be reviewed to see if it can be adequately and economically expanded.
Most important is the ability to handle and dispose of large volumes of water economically. The ultimate recovery will be dictated by economics which are functions of both water/oil ratio and a minimum oil rate.
Because at abandonment conditions the fixed costs are generally higher than the disposal and lift costs, abandonment conditions in general tend to be more a function of oil rate than water/oil ratio.13
ACKNOWLEDGMENTS
We wish to thank Pertamina, Maxus Energy Corp., Maxus Southeast Sumatra, and the Southeast Sumatra contract area partners for permission to publish this article. The contributions of S. J. Notch and the following Maxus employees are appreciated: R. M. Parker, R. J. Cruz-Ahedo, B. L. Boone, P. P. Kovacs, D. W. Straw, P. A. Roe, and J. C. Hill.
REFERENCES
- Bushnell, D.C., and Temansja, A.D., "A Model for Hydrocarbon Accumulation in Sunda Basin, West Java Sea," Proceedings of the 15th Annual Convention, Indonesian Petroleum Association, 1986, pp. 48-75.
- Rose, J.D., "Case History-Installation of High Volume Pumping Equipment in Talco Field, Texas," Paper No. SPE 11040, SPE 57th Annual Fall Technical Conference and Exhibition, New Orleans, Sept. 26-29, 1982.
- Whiting, R.L., "Application of Electrical Submersible Pumps in Natural and Artificial Water-Drive Reservoirs "Paper No. SPE 18191 SPE 63rd Annual Technical Conference and Exhibition, Houston, Oct. 2-5, 1988.
- Rose, W., and Cleary, J., "Further Indications of Pore Doublet Theory," Production Monthly, January 1958, pp. 20-25.
- Slobod, R.L., "Comments on Trapping Oil in a Pore Doublet," Production Monthly, January 1957, p. 17.
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- Abrams, A., "The Influence of Fluid Viscosity, Interfacial Tension, and Flow Velocity on Residual Oil Saturation Left by Waterflood," Society of Petroleum Engineering Journal, October 1975, pp. 437-47.
- Jordan, J.K., McCardell, W.M., and Hocott, C.R., "Effect of Rate on Oil Recovery by Waterflooding," report for Humble Oil & Refining Co., Houston, 1956.
- Melrose, J.C., and Brandner, C.F., "Role of Capillary Forces in Determining Microscopic Displacement Efficiency for Oil Recovery by Waterflooding," Journal of Canadian Petroleum Technology, October-December 1974, pp. 54-62.
- Moore, T.F., and Slobod, R.L., "The Effect of Viscosity and Capillarity on the Displacement of Oil by Water," Production Monthly, August 1956, pp. 20-30.
- Taber, J.J., "Dynamic and Static Forces Required to Remove a Discontinuous Oil Phase From Porous Media Containing Both Oil and Water," Society Petroleum Engineers Journal, March 1969, pp. 3-12.
- Taber, J.J., Kirby, J.C., and Schroeder, F.U., "Studies on the Displacement of Residual Oil, Viscosity and Permeability Effects," Symposium Series, American Institute of Chemical Engineers, Vol. 69, No. 127, 1973, pp. 53-56.
- Beveridge, S.B., Agrawal, R.K., Coats, K.H., and Modine, A.D., "Can Higher Production Rates Reduce the Current Energy Problem Without Impairing Recovery?" Paper No. 374005, 25th Annual Technical Meeting of the Petroleum Society of CIM, Calgary, May 7-10, 1974.
- Miller, R.T., and Rogers, W.L., "Performance of Oil Wells in Bottom Water Drive Reservoirs," Paper No. SPE 4633, SPE 48th Annual Fall Meeting, Las Vegas, Sept. 30-Oct. 3, 1973.
- Reed, R.N., and Wheatley, M.J., "Oil and Water Production in a Reservoir With Significant Capillary Transition Zone," Paper No. SPE 12066, SPE 58th Annual Technical Conference and Exhibition, San Francisco, Oct. 5-8, 1983.
- Blades, D.N., and Stright, D.H., Jr., "Predicting High Volume Lift Performance in Wells Coning Water," 26th Annual Technical Meeting of the Petroleum Society of CIM, Banff, Alta., June 11-13, 1975.
- Permyakov, I.G., and Gadok, N.S., "The Desirability of Exploitation of Oil Fields at High Rates of Oil Production," Neftyanoe Khoz., Vol. 39, No. 6, 1961, pp. 33-68.
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