SPE-178106-MS Reservoir Management Through Water Injection Surveillance in Block X of Mumbai High South Field- A Case Study Archana Kamath, Bipin Gedam, C. R. Maurya, J. P. Kukreja, and Mahendra Pratap, Oil and Natural Gas Corporation Limited
Copyright 2015, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Oil and Gas India Conference and Exhibition held in Mumbai, India, 24 –26 November 2015. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract Water-flood management is an exploitation strategy adopted in Mumbai High field to maintain the reservoir health. Pressure sinks are seen developing in Block X of the south field as a result of inadequate water injection. Efforts to increase water injection in this area based on analysis of injection wells using various water-flood surveillance tools resulted in arresting decline, increase in water retention and reservoir pressure. As a part of the study, the performance of injectors was analysed with their effect on nearby producers. Various classical techniques for water-flood surveillance viz. injection performance curve vs. time incorporating events, Hall’s plot, ABC plot, backwash analysis, PLT report analysis, pressure vs. time plot, production performance curve vs. time incorporating events, water cut and GOR vs. time plot, WOR vs. cumulative oil production plot and bubble mapping were utilized to monitor the efficiency and take corrective actions to improve the health of the reservoir. The study area is located in the peripheral part to the west of WI-X1 injection platform of the MH south field. The area was developed by platforms I1, I2 and I3 (1993-94) by conventional wells, but had limited productivity/ injectivity. Further development was done by horizontal/ multilateral wells from I4 (200205), where the horizontal wells produced with high initial rates, that declined sharply, more prominently in wells towards west away from injection platforms. The high decline could be attributed to negligible pressure support from western natural aquifer influx and tight reservoir characteristics leading to poor pressure transmissibility from the eastern injection platforms. The problem was aggravated by less water injection than envisaged rate resulting in decline in production, drop in reservoir pressure, low water retention and low incremental voidage replacement ratio (0.45). To increase the injection support 3 more water injectors were added that resulted in an increase of injection from 17,500 to 31,800 BWPD. This led to increase in incremental VRR to 1.80 and water retention to 88%, which has shown positive response in jacking up pressures in this area and arresting of oil production decline per string from 14% to 4% with flattened WOR. The present study emphasises the importance of maintaining incremental VRR greater than 1.0 and reducing circulation of injection water by conversions in appropriate places with respect to producers along with optimised rates in existing injectors to improve the recovery in tight reservoir conditions.
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Introduction Mumbai High field is a giant oil field located in western offshore, 165 km west of Mumbai city. It is a highly complex carbonate reservoir covering about 1700 sq km area. It is a doubly plunging anticline with gently dipping limbs and is bounded by a NNW-SSE trending fault on its eastern boundary. The two main limestone oil reservoirs are pay zones L-II and L-III of Miocene age. The L-III pay zone holds approximately 94% of the total initial oil in place of the field. It is a multilayered carbonate reservoir with a gas cap and partial water drive. The L-III pay zone is divided into 2 blocks namely Mumbai High North (MHN) and Mumbai High South (MHS) on the basis of E-W trending impermeable shale channel. The L-III reservoir of MHS was put on production in Oct-80 and to arrest production decline water injection commenced in Mar-87 through western peripheral water injection row platforms WI-X1, X2, X3 and X4. The water injection platforms WI-X1 and X2 indicated extension of western boundary due to flattening of the geological structure and established the oil production potential of peripheral area west of water injection platforms. In this area, the top most sub layer of L-III reservoir (A1) is oil bearing layer and all other layers are either tight or poor in hydrocarbon saturation. Block X is located to the west of WI-X1 injection platform. The area was developed by platforms I1, I2 and I3 (1993-94) by conventional wells, having limited productivity/ injectivity. Horizontal/ multilateral well technology was used to further develop the peripheral area. These horizontal/ multilateral wells were drilled from I4 (2002-05). Addtional horizontal wells were drilled from clamp-on installed on I1, I2 and I3 platforms. The horizontal wells produced with high initial rates that declined sharply, more prominently in wells towards west, away from injection platforms. The high decline could be attributed to negligible pressure support from western natural aquifer influx and tight reservoir characteristics leading to poor pressure transmissibility from eastern injection platforms. The support from existing injectors in the production platforms was confined mainly to the individual platform area. The higher fluid withdrawal from the horizontal wells increased the gap between voidage created and its compensation by water injection in Block X. This problem was further aggravated by lesser water injection than envisaged. Water-flood management is an exploitation strategy adopted in Mumbai High field to maintain the reservoir health. Pressure sinks are seen developing in Block X of the south field as a result of inadequate water injection. Efforts to increase water injection in this area based on analysis of injection wells using various water-flood surveillance tools resulted in arresting decline, increase in water retention and reservoir pressure.
Surveillance Methodology The area was studied for the performance of existing water injectors with their effect on near by producers. Three oilproducer wells I4-12, I2-12 and I3-9 were converted to water injector wells in 2014(Fig.1). The wells I2-12 and I4-12 are located in the periphery and are placed structurally lower than the nearby oil producers (Fig.2). The impact of the increased water injection is being monitored through periodical measurements of liquid rate (ql), oil rate (qo), water cut, WOR (Water/Oil Ratio) vsNp (cumulative oil production) plot, GOR (Gas/Oil Ratio) vs time plot, VRR (Voidage Replacement Ratio) vs time plot, pressure vs time plot and water retention vs time on block level. Individual injector wells are monitored by ABC (After/Before Comparison) Plot, backwash analysis, water injection performance vs time and Hall’s plot.
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Figure 1—Location Map of Block X
Figure 2—Depth structure Map at Reservoir top in Block X
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Results There are 29 oil producer wells in this block, out of which 9 are conventional and 20 are horizontal wells. Among the 29 oil producer wells, currently 2 wells are closed. The total number of water injector wells is 15, out of which 9 are conventional and 6 are horizontal wells (Fig.1). A total of 3 injector wells are closed at present due to various reasons. Remedial actions to start injection in these closed wells are being planned. The injection rate has been improved to approximately 40,000 BWPD (Fig. 3) and the injectivity per string has been improved from 1500 BWPD per string to 3300 BWPD per string (Fig. 4). The VRR (Voidage Replacement Ratio) vs time shows increase to 1.80 (Fig. 5), and the CVRR (Cumulative Voidage Replacement Ratio) vs time shows improvement from 0.39 to 0.44 (Fig. 6).
Figure 3—Water injection Performance (Block X)
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Figure 4 —Injectivity per string vs time
Figure 5—VRR (Voidage Replacement Ratio) of Block X vs Time
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Figure 6 —CVRR (Cumulative Voidage Replacement Ratio) of Block Xvs time
The WOR (Water/ Oil Ratio) vs Np plot shows flattening (Fig. 7). The pressure response to increase in water injection is positive as seen in Fig. 8. The decline in production has been arrested with stabilized rate around 7,000 BOPD (Fig. 9).
Figure 7—WOR (Water/ Oil Ratio) vsNp
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Figure 8 —Pressure vs Time
Figure 9 —Production Performance vs Time
The backwash samples of water injector wells were analysed and accordingly the frequency to carry out backwash in the water injector wells is maintained at approximately 6 months. Regular backwash in injector wells has enabled in maintaining the required rate of injection and improving quality of injection
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water. The prebackwash and post backwash test data showed that an average of 400 BWPD increase in injection rate is achieved. For quick analysis of the water injector wells, the injection rates and pressures were plotted at two separate dates and an ABC (After/Before Comparison) plot was generated. The ABC (After/Before Comparison) Plot for water injector wells in Block X was prepared between August 2014 and August 2015 (Fig. 11). The injector wells falling in the unit slope area indicate healthy injectors. There are 4 injectors (I1-5, I2-7, I3-4 and I3-5) in this block lying in the normal trend. The wells falling to the left of the unit slope indicate impairment in injection. In Block X there are 4 wells (I1-9, I2-6, I2-9 and I3-9) which fall in this category. After analyzing the water injection performance of each of these 4 wells it was recommended to carry out acid job in well I1-9. No action is recommended for well I3-9 though it falls in the injection impairment category because it was initially injecting at rate more than required and now the injection rate has stabilized. Well I2-6 has been recommended for backwash to achieve the desired rate. Well I2-9 which falls in the injection impairment category has been recommended for rate optimization because it is currently injecting at rate more than desired and therefore will lead to early breakthrough in nearby oil producers if not controlled. The area to the right of unit slope indicates water injection loss in thief zones. In this block 4 wells (I1-8, I1-10, I2-12 and I4-12) are falling under this category. No action is recommended in I1-8 well because it lies very close to the unit slope. The well I1-10 is recommended for choke optimization to increase injection though it falls in the category loss of injection water through thief zone, because it is injecting with rate lesser than required to maintain pressure. Well I2-12 is recommended to install choke to reduce the loss of injection water in thief zone. Well I4-12 is identified for stimulation though it is falling in the category loss of water injection, because this well is at present injecting with rate lesser than required.
Figure 10 —Water cut and GOR (Gas/ Oil Ratio) vs Time
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Figure 11—ABC (After Before Comparison) Plot
Individual water injector wells have been analysed on the basis of injection performance and it was recommended to inject water at rate 31,500 BWPD as against current injection rate of 32,187 BWPD (measured rate) to ensure efficient sweep without early breakthrough of water in producer wells. The remedial actions to be taken for controlled injection is currently being implemented. This has resulted in decrease in water cut in producer wells (Fig. 10). The VRR of this block will remain greater than 1 with recommended rate. An addition of 7,500 BWPD is expected from injection resumption in 3 wells that are closed at present. The Hall’s plot is a technique for continuous monitoring that was developed by Howard Hall in 1963. It is an effective way to process water injection information. The main concept is to plot a cumulative pressure time product against the cumulative volume of water that has been injected. The plot gives an indication of the injection behavior; a change in injectivity appears as a change in the slope of this plot. The cumulative summing reduces fluctuations in the injectivity index. These fluctuations can be due to inaccurate measurements/recording or transient effects caused by operational or reservoir changes. These plots make it easier to identify real changes in injectivity trends. Based on Hall’s plot for individual wells and stimulation history, stimulation jobs in 9 water injector wells were carried out and an increase of 2500 BWPD was achieved. In addition, one well I1-9 is also identified for acid job to achieve desired injection rate.
Conclusions 1. Water flood in MHS as on date remains the known cost-effective process to improve the recovery. Therefore, water flood surveillance attains priority in view of the by-passed oil in this mature field. There are several techniques for constructing a reliable surveillance model, but the conventional approach using various diagnostic plots still retains its utility. 2. The conventional surveillance tools utilized in combination have been applied in a particular Block
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X of MHS field. The limited impact of the eastern injector on western part has been mitigated by the conversion of producer wells to water injectors in the western boundary. 3. An injection rate of 31,500 BWPD is recommended as against the current injection of 32,187 BWPD (measured rate) to reduce water cut in nearby producers and ensure efficient sweep. The VRR will remain greater than 1 with recommended rates. 4. Stimulation jobs in 9 water injector wells were carried out based on Hall’s plot analysis and an increase of 2500 BWPD was achieved. 2 more wells I1-9 and I4-12 are recommended for acid job to improve injection in desired area. 5. 3 wells I1-10, I2-9 and I2-12 are lined up for choke optimization, thereby ensuring better sweep efficiency. 6. Conversion of wells to water injector in the western periphery (I2-12 and I4-12) has resulted into arresting the declining reservoir pressure.
Acknowledgement The authors express their sincere gratitude to the ONGC management for providing the opportunity to prepare and publish the paper. The authors are deeply indebted to Shri Rajesh Kakkar, ED-Asset Manager, MH Asset, for his constant support, guidance and encouragement to present this paper. The authors also wish to acknowledge the efforts put in by offshore personnel, and surface team of MH Asset for generating the test data utilized in the present study. Nomenclature ABC after/ before comparison BLPD barrels of liquid per day BOPD barrels of oil per day BWPD barrels of water per day B/D barrels per day CVRR cumulative voidage replacement ratio Np cumulative oil produced GOR gas/ oil ratio ITHP injection tubing head pressure kilogram per square centimetre kg/cm2 MMt million metric tonnes MMm僐 million cubic metre VRR voidage replacement ratio WOR water/ oil ratio W/C water cut
References 1. Water Control Diagnostic Plots by, K. S. Chan, Schlumber Dowell (SPE 30775) 2. Water Injection Surveillance in large off shore carbonate reservoir of Mumbai High- A Case Study by AK Sharma, Archana Kamath, MM Roy, SK Verma (Geoindia PD 658) 3. Waterflood surveillance and control: Incorporating Hall Plot and Slope Analysis by, D.B. Silin et al. (SPE 95685) 4. Integrated Waterflood Asset Management by Ganesh, C. Thakur, AbdusSatter. March 1998 5. Waterflooding Surveillance and Monitoring: Putting Principles Into Practice, M. Terrado, S. Yudono, and, G. Thakur, Chevron Energy Technology Co. (SPE 102200)
