SPE 116989 Short-Term and Long-Term Aspects of a Water Injection Strategy Bruno A. Stenger, Abdulla B. Al-Katheeri, Hafez H. Hafez, Salem H. Al-Kendi, ADCO, SPE Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 3–6 November 2008. 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 This paper reviewed the water injection strategy of a supergiant carbonate oil field operated by ADCO onshore Abu Dhabi since 1973. This field was subjected to peripheral waterflooding in order to maintain reservoir pressure and provide a mechanism to sweep the oil. In addition to traditional parameters in waterflooding such as for instance, reservoir heterogeneity, mobility ratio and depletion rate that control the waterfont shape, the presence of three oil-bearing reservoirs juxtaposed across strike-slip fault planes added a new variable to the complexity. Fault juxtaposition was interpreted to create limited pressure communication and fluid crossflow between reservoirs. The usual way of computing the voidage replacement ratio based on well production and injection rates was therefore insufficient to gain a complete understanding of the water injection strategy. Two different solutions of the voidage replacement ratio were computed using a full-field reservoir simulation model history-matched for both pressure and saturation changes. After accounting for all surface facilities constraints and under a certain set of assumptions, results of this model indicated that crossflow magnitude was minimized when certain pressure differences were maintained between these three reservoirs. Alternatively, there were some indications that higher crossflow could result in some additional oil recovery. A simple methodology to manage production and water injection targets on a quarterly basis while accounting for the communication between reservoirs was discussed. Finally implications for an on-going development were reviewed. Introduction Field W was located onshore about 110 km southwest of Abu Dhabi City in the United Arab Emirates. Three major Lower Cretaceous oil-bearing reservoirs, X, Y and Z, contained undersaturated oil with reservoirs Y and Z under commercial production since 1973, and reservoir X development on-going with plateau production expected by end of 2012. Reservoirs Y and Z were undergoing peripheral waterflooding with a mixed wet producing strategy whereby wet wells were produced until natural flow ceased. Subsequently, rigless water shutoff opportunities and revival via artificial lift were deployed. Reservoir X development called for a peripheral water injection scheme, targeting the bottom part of the reservoir, combined with a crestal immiscible WAG line drive, targeting the upper part of the reservoir. Waterflooding was clearly the secondary recovery method of choice for all three reservoirs. The next paragraph reviewed the field evidence and determined to what extent all three reservoirs were deemed to be in pressure communication. Review of Field Data Field Structure Field W was a low-relief anticline with its main axis trending NE-SW thought to reflect some deep-seated basement faults regularly reactivated since the Precambrian (Ayres et al., 1982). Field W structure is about 30 km long and 10 km wide. Several major fault corridors trending N110E and some radial extensional faults in the northern tip of the structure were mapped from 3D seismic interpretation (Figure 1a). The major fracture corridors seemed to be regularly spaced every 3 to 4 kilometers along the field main axis. The examination of the fault pattern (Figure 1b) revealed a typical shearing system with associated secondary Riedel N135E fractures confirming a right-lateral (dextral) displacement as discussed in previous publications (Silva et al., 1996, Melville et al., 2004). Extensional fractures trending N15W were also clearly imaged at an angle of 55o to the main fault trending N110E and occasionally extending to merge and act as relay between the main strike-slip fracture corridors. A third fracture system trending NS was detected at about 70o from the main fault direction, providing the necessary clockwise rotational component to accommodate the lateral displacement and release the shearing stress; this NS fracture direction was interpreted as being the conjugated left-lateral (sinistral) Riedel fracture. A schematic interpretation summarized all 2 fractures identified for this field (Figure 1c). At first look, the interpretation pointed to an apparent maximum horizontal compressive palaeo stress direction of N40W, not in line with any of the known maximum horizontal stress directions that affected this region (1) the older Paleozoic and Mesozoic E-W “Oman” stress regime, and (2) the more recent Cenozoic N-S “Zagros” stress regime. A similar conclusion was reached for another oil field in the same concession with a palaeo stress deemed to trend N60W (Gomes et al., 2006). Instead, the authors proposed a new interpretation in which the sinistral N40-50E fracture direction observed offshore Abu Dhabi (Marzouk and Sattar, 1994) and the dextral N110E fracture direction observed onshore Abu Dhabi are conjugate shearing faults with a maximum horizontal palaeo compressive stress oriented N70-80E and consistent in orientation with the E-W “Omani” stress regime (Figure 1d). It was the authors’ view that in this field the “Zagros” stress regime re-activated this strike-slip system with a N110E dextral (opposite) slip. A possible explanation for the preferential development of N45E sinistral strike-slip faults in the north of the basin (offshore Abu Dhabi) and N110E dextral in the south of the basin (onshore Abu Dhabi) could reside in the existence of an independent tectonic block bounded to the north by the Trans-Arabian Gulf sinistral fault (Weijermars, 1998) (Figure 1e). In the field under study, fault throw was modest in general but considering that reservoirs X, Y and Z were vertically separated by dense limestone beds of 20 to 30 feet only, even a small vertical offset would be enough to juxtapose reservoirs and create a lateral communication path (Figure 2). Wrench tectonics created situations with localized reverse faulting and increased complexity of juxtaposition between reservoirs. Pull-aparts and extensional fractures could also open direct vertical communication between reservoirs. It was therefore concluded that field W was in a known tectonic setting and that its interpreted fault pattern indicated the likelihood of (1) lateral communication between reservoirs through juxtaposition and (2) vertical communication through pull-aparts and extensional fractures. Reservoirs X, Y and Z were vertically separated by dense limestones that were essentially non-pay intervals. Stylolites were observed on cores taken across these intervals (Figure 3) and previously described in the literature (Koepnick, 1987; Al Sharhan and Sadd, 2000). Stylolites were considered as playing an important role in the local restriction of vertical communication between and within reservoirs; laterally, continuity of stylolites might be interrupted through faulting and fracturing. Within each reservoir, denser intervals were used to define a subzonation of the producing units generally in Upper and Lower subzones. Intra-reservoir dense sublayers with sufficient thickness were clearly visible on 3D seismic cross-sections as thick non-pay intervals downflank that could thin and disappear on the crest of the field (Figure 4). Reservoir Oil and Aquifer Brine SPE 116989 Although pre-production fluid analyses were scarce, it was verified repeatedly that crude oil properties were very similar between reservoirs X, Y and Z to a point that variability in composition between bottomhole samples in one well was larger than any differences measured between oil sampled in the three reservoirs. Bubble point pressure of 2,220 psi at 250 oF, solution gas-oil ratio of 850 scf/stb, molar composition all indicated similar sweet crude with API of 38 degrees. The only notable difference was linked to the asphaltene content in the northern part of the field where core data indicated an increase of bitumen content in the bottom thirty feet of reservoir Y. This localized increase in bitumen was not fully understood yet although its basal structural position within a lower permeability subzone could indicate a palaeo-OWC and the consequent formation of a tarmat at the OWC interface. Aquifer brine was sampled from reservoirs Y and Z early in the field life with a salinity ranging from 157,000 to 188,000 ppm TDS. Onshore Abu Dhabi, the salinity of the overlying Umm Er Radhuma (Palaeocene) and Simsima (Upper Cretaceous) aquifers was 254,000 ppm TDS at reservoir conditions and clearly higher than the salinity measured in reservoirs X, Y and Z. No definitive explanation was available for the higher salinity in Umm Er Radhuma and Simsima aquifers although the overlying Rus formation (Early Eocene) was known to contain evaporites. In summary, known oil and brine properties seemed to indicate similar fluids in all three reservoirs. Static Reservoir Pressure and Fluid Contacts Initial static reservoir pressure of 3,930 psia at -7,700 feet tvdss indicated hydrostatic and static pressure conditions across all three reservoirs. Original oil water contacts (OOWC) were found at similar depths in reservoirs Y and Z. Indications that the OOWC was shallower in reservoir X might result from a larger transition zone in a reservoir of lower permeability. It was generally accepted that all three reservoirs shared a common free water level of 7,920 feet tvdss. Early Reservoir Pressure Evolution From late 1973 to early 1976, reservoirs Y and Z produced under primary depletion in order to determine the level of aquifer support and select the appropriate full field development strategy. The rapid reservoir pressure decline in reservoirs Y and Z indicated minimal aquifer support (Figure 5). The large pressure depletion in reservoir X (red dots) was explained through commingled production with reservoir Y in two early producers, a practice that was discontinued after 1976. As expected in commingled completions, measured pressure in reservoir X (low permeability) was tracking reservoir Y (high permeability) pressure perfectly. Reservoir Z pressure was obviously higher than reservoir Y suggesting perhaps a restricted communication between the two reservoirs. Since both reservoirs were of a different size and produced at different rates, this plot was not sufficient to draw a clear conclusion. A material SPE 116989 balance using the Carter-Tracy water influx function and the Fanchi polynomial coefficients was applied for both reservoirs during the primary depletion phase from December 1973 to December 1975. A good match of the historical reservoir pressures was obtained using a very small Carter-Tracy aquifer with reD of 1.5 (large dots on figure 5). These observations were consistent with a limited aquifer support as frequently observed in the large carbonate oil fields of the Arabian Peninsula as reservoir development and permeability dropped dramatically off structure. The apparent reservoir compressibility was equal to the slope of the trends plotted for each reservoir (Figure 6). This plot revealed that the reservoir pressure of reservoirs Y and Z behaved similarly when plotted against the volumetric depletion of their respective oil in place volumes. After reaching respectively a cumulative production of 2.8% and 2.0% of their original oil in place (OOIP), reservoir Y and reservoir Z pressure declines were drastically reduced as gravity water injection started at high rates during the first quarter of 1976 and pressure maintenance was felt very quickly due to the high reservoir permeability in reservoirs Y and Z. Peripheral water injection was implemented in order to maintain reservoir pressure in the producing reservoirs, first using gravity water injectors from early 1976 then pumping and re-injecting aquifer brines after 1984. As it was commonly noted when gravity water injection was used, there were some uncertainties in the gravity water injection rate history as injection rate was not measured on a regular basis and was generally dropping in proportion to the building backpressure on the injecting aquifers. By difference, cumulative gravity water injection for reservoirs Y and Z was recomputed using the Carter-tracy material balance equations history matched in the previous step. In the case of reservoir Y, it was found that the recalculated gravity water injection rate history could be somewhat higher in the early times (Figure 7). Early pressure data were found to be of good quality for this field, a testimony to the professionals who initiated the development and did not sacrifice data acquisition. A material balance analysis of these data showed that no firm conclusion could be made as far as communication between reservoirs Y and C was concerned. In particular the pressure differential of 250-300 psi between reservoirs Y and Z could apparently result from a lower level of depletion in reservoir Z when gravity water injection started and the maintenance of similar voidage replacement ratios in both reservoirs. On the other hand, a restricted communication was still compatible with the available pressure measurements. Reservoir Pressure Evolution during Powered Water Injection Powered water injection was initiated in 1984 in order to help increase reservoir pressure in the center of the field and sustain the natural flow of maturing producers in the periphery. Historical reservoir pressures showed the typical scattering that was a function of the distance between the observation point and the row of peripheral 3 water injectors, reservoir permeability and level of production. Reservoir X had been shut in from 1976 to mid 1990 after two early commingled producers were re-completed and reservoir X perforations squeezed off. No pressure measurement was made during the shut-in period because no wells had opened perforations in reservoir X except for a RFT acquired in a first-row producer across reservoirs X, Y and Z in February 1989. Since the well location was close to the eastern row of water injectors, the pressure levels in reservoirs Y and Z could be influenced by the near-by water injectors. This RFT indicated however a pressure differential of 200 psi between reservoirs X and Y. Upon resuming production from reservoir X in July 1990, reservoir X pressure was measured in two crestal wells that had been recompleted and pressure was found to have declined to 2,900 psia at datum of -7,700’ ft tvdss. A comparison with near-by wells completed in reservoir Y showed that a pressure differential of 230-300 psi existed between reservoirs X and Y in July 1990 (Figure 8). As production resumed, reservoir X pressure declined and coincidentally became superimposed with reservoir Y Lower pressure. Some firm evidence was therefore indicating that reservoir X pressure had continued to decline during the 14-year shut-in period although the pressure differential of 230-300 psi at datum showed unequivocally that pressure communication was only partial. Fluid Saturation Interpretations Full suites of conventional openhole logs were routinely acquired in development wells and were covering reservoirs X, Y and Z. Several water saturation anomalies were recorded in reservoir X with two classical cases shown here as examples (Figure 9). These wells were drilled in major fracture corridors and openhole logs identified very high water saturation in the lower part of reservoir X that should have been oil-bearing since reservoir X was not being developed or produced at the time of logging those wells. The presence of water in reservoir X was linked to the waterflooding of reservoir Y and vertical gravity slumping through the faulted/fractured zones with the well under consideration clearly drilled in a (pull-apart) downthrown block with about 50 feet of throw (Figure 10). Reservoir Y is made up of two major subzones with much higher permeability in Y Upper. By the time the well illustrated in figure 10 was drilled in 2003, injection water had encroached in most of subzone Y Upper after 30 years of plateau production. The possibility of water crossflow during drilling was not considered likely since (1) this situation was observed in a limited number of wells and (2) all wells were drilled with same mud overbalance of 250 to 300 psi. Preliminary Findings It is concluded that some degree of vertical communication existed between reservoirs X, Y and Z especially near the major fault corridors where reservoir sections could be juxtaposed or pull-apart features were interpreted from 3D seismic imaging. Communication 4 behind casing was ruled out since existing cement bond logging data showed that usually, cement bond quality was good across the inter-reservoir dense layers. The authors were therefore confident that the analysis of early reservoir pressure data had produced conclusive evidence that reservoirs X, Y and Z were experiencing some degree of pressure communication along fracture corridors. A pressure threshold of 200-300 psi was deduced from the analysis presented here and could be used as a calibration point in reservoir models. Anomalous water encroachment found in reservoir X was successfully linked to pull-apart features along major fracture corridors with gravity water slumping in downthrown blocks as the most likely mechanism for the water presence in reservoir X. Reservoir modeling and reservoir simulation were the tools of choice to further understand the interaction between the three reservoirs and reproduce the historical data as discussed in the next section. Reservoir Modelling Historically, reservoir simulation models were restricted in size due to limited computer resources. With the recent increase of computational power and parallel processing, previous limitations in grid cell size and number of cells had been overcome and allowed running routinely models with a million active cells or more. In the case under discussion, this translated into building the first ever high-resolution (finely layered) reservoir simulation model combining all three reservoirs. The importance of having fine layers across faultjuxtaposed blocks was therefore critical. Previously, nonneighbour connections had provided a numericallyefficient way of connecting layers through fault planes. Non-neighbour connections were found however cumbersome to establish and not very practical to modify in a consistent manner along 10-km long faults with variable throw during a history matching process. Although finer layers did resolve the issue of reservoir juxtaposition and direct lateral communication across major faults, subseismic faults had to be invoked in some cases and only non-neighbour connection could establish the required communication in the absence of any visible fault throw. Previously, a set of three models based on the same structural framework had been history matched. These three models consisted of (1) finely layered reservoir X with coarsely layered reservoir Y, (2) finely layered reservoir Y with coarsely layered reservoirs X and Z and (3) finely layered reservoir Z with coarsely layered reservoir Y. Fine layers were extracted from the three models with all associated properties and merged into a single fine resolution model (Figure 11). Main matching parameter was the adjustment of fault transmissivity and non-neighbour connections. A very good pressure history matching was achieved in a few months (Figure 12). The next step was to leverage the insight from the reservoir simulation model into the deployment of an efficient water injection strategy for the three reservoirs. SPE 116989 Short-Term Management of Water Injection Highly saline water was produced from Simsima and Umm Er Radhuma aquifers using electrical submersible pumps with capacity of 30,000 bwpd. Twenty-three water injection clusters circled the field periphery with interconnection to ensure that each water supply well could share its supply with neighboring clusters as a backup during maintenance shutdowns (Figure 13). Each cluster was equipped with a surface injection booster pump with a capacity of 30,000 bwpd and outlet pressure of 2000 psi. Water injection targets were defined on a quarterly basis to match the water supply availability and distribute the water between injectors in order to optimize voidage replacement ratio. Since this field extended over 280 square kilometers, water injection allocation needed to be calculated by sector. The field was therefore divided into eleven regions for each subdivion of the three reservoirs (Lower and Upper) yielding a total of 22 regions per reservoir. As much as possible, region boundaries were based on the fault system described before. Since the no-flow boundary assumption between the producing regions was not an acceptable approximation in this case, interaction coefficients were derived from the simulation model by increasing the injection rate in one cluster only and calculating the pressure differential it created in all regions after a number of years with all others rate constraints being held identical; a total of 23 runs were necessary to obtain all coefficients of influence expressed in psi after five years of injection. After normalizing by the larger pressure differential recorded, a matrix of influence was derived. The matrix of influence was used to distribute the effect of water injection among different regions rather than allocating it all to one region only as a classical approach would dictate, which would be clearly wrong in case the no-flow boundary assumption between regions was not fulfilled. Since reservoirs X, Y and Z have been shown to be in pressure communication, fluid fluxes between reservoirs were also extracted region by region from the simulation model and included in a modified version of the classical voidage replacement ratio equal to the sum of all fluxes entering the region divided by the sum of all fluxes leaving the region. Two ways of calculating the voidage replacement ratio were therefore available and used to complement/check each other. The implementation of this methodology required the coding of visual basic macros using well-known spreadsheet software. These macros have permitted to unify the distribution of oil production and water injection targets string by string in a very efficient and reliable manner for a field with several hundreds of producing strings at different stages of maturity. Results could be plotted easily as bubble maps to ensure a visual check of a proper rate distribution by region. Voidage replacement ratios were remarkably maintained throughout history with a very good balance between regions. SPE 116989 Long-Term Management of Water Injection The authors have demonstrated that reservoirs X, Y and Z were in communication along major fracture corridors. The history-matched combined model was used to estimate the cumulative oil and water volumes exchanged between reservoirs during the historical period and for the next fifty years of operation. Several levels of pressure maintenance in the oil producing areas were assigned as targets and the reservoir simulator was instructed to adjust water injection rates in order to match the reservoir pressure targets while respecting all surface facilities constraints. Sixteen production forecasts were run using different reservoir pressure targets for each reservoir. Results indicated that maintaining the current pressure levels in each reservoir (blue dot on figure 14) would minimize future crossflow between reservoirs as expected (Figure 14). It was indeed predictable that the current pressure regime reflected a situation of stable equilibrium after more than thirty years of balanced powered peripheral water injection. Higher recovery was obtained when the pressure differential between reservoirs Y and Z was 100 psi higher than the pressure differential between reservoirs X and Y due to differences in cross flow directions. Compressibility effects (blow down) were also evident in case pressure was allowed to reduce down to 2900/3100/3400 psi in reservoir X/Y/Z respectively with little additional crossflow since the pressure differential between reservoirs was maintained compared to the actual case. Reducing pressure in all three reservoirs to 3000 psi would lead to the highest cumulative oil recovered although it would be at the risk of large additional crossflow between reservoirs. Care must be exercised in all cases since any extra recovery would come at time of high reservoir maturity and high watercut in subzone Y Upper in particular when reservoir simulation predictions are highly dependent on the accuracy of low relative permeability values and residual oil saturation. Since early 2008, the subsurface development team used commercial software to apply an experimental design approach in order to quantify the effect of subsurface uncertainties on the development plan deliverables such as plateau production duration and reserves recovered at a cut-off date. The same software was used to accelerate the history matching process for the gas and water injection pilots with interesting conclusions on a likely anisotropy in the horizontal permeability, possibly linked with the fracturing pattern described earlier. After populating the full field model with the modified reservoir properties, the overall history matching quality of the full field model improved noticeably. These preliminary results were found significantly encouraging and warranted further work. Reservoir X Development Strategy Reservoir X full field development plan was recently approved. The optimum drive mechanism was identified as a peripheral water injection system coupled with an immiscible Water Alternate Gas (WAG) sparse line drive on the crest of the reservoir. With this perspective, the 5 need to properly understand and locate pressure communication and crossflow between reservoirs X and Y could not be overstated. Since 1998 and 2002 respectively, a water injection and a gas injection pilot had been in operation in reservoir X to obtain information on the sweep efficiency and timing of water and gas breakthroughs. Since September 2007, both pilots were converted to WAG with 3-month cycles and 1:1 ratio having been determined as the most efficient parameters using reservoir simulation models. Pressure fall-off tests were regularly acquired at the end of each cycle to check for gas or water blockage effects. Since 2004, three pairs of peripheral water injection wells and first row horizontal producers were put on stream in order to evaluate the pressure transfer in a low permeability reservoir. All pilots were monitored on a quarterly basis and the results were used to fine tune the development plans. For instance, declining injectivity in peripheral water injectors resulted in a combined effort to increase injectivity by drilling longer horizontal wells, enhancing stimulation practices and reducing the count and maximum size of suspended particles in the injected water. Fine water filtering was believed to have a significative positive effect on reservoir X water injector life. This was confirmed in a recent study conducted on the Ghawar field in Saudi Arabia (Evans et al. 2004). In the case of reservoir X development, water quality was identified as a critical parameter to maintain injection conformance in the the crestal WAG wells that were targeting the upper subzone of reservoir X. Since fractures could not be allowed to propagate into the lower subzone, water quality was essential to avoid plugging the fine pores of the upper subzone that would inevitably trigger an increase in downhole pressure and raise the risk of developing a fracture. By itself, fine water filtering might not be sufficient to ensure WAG wells did not develop fractures since lower temperature was playing a key role in reducing the rock ability to bear tensional stresses at the wellbore face. Permanent downhole pressure and temperature gauges were therefore added to the WAG completion kit in order to keep a firm monitoring of these complex interactions. Conclusions At field level, the N110E dextral strike-slip was shown to be consistent with a North-South “Zagros” maximum horizontal stress re-activating a conjugated fault direction initiated during the N70-80E “Omani” compression phase. Pull-apart features along major dextral fracture corridors were identified and explained water saturation anomalies in the then undeveloped topmost oil-bearing reservoir X. Pressure communication was successfully linked not only to lateral communication through reservoir juxtaposition. Transtensional fractures with no identifiable vertical displacement were also interpreted and could provide additional vertical communication in the central part of the field. A comprehensive review of the water injection strategy applied in a supergiant oil field operated onshore Abu 6 Dhabi since 1973 has led to some interesting insights that were integrated in the next phases of development. Acknowledgements The authors wished to thank ADCO and ADNOC management for permission to prepare, publish and present this paper. The authors acknowledged the contributions from Peter Melville who interpreted the 3D seismic cube, David Sousa who coded the first macro used to distribute the production targets by region, Pradyumna R. Chaliha for the derivation of influence coefficients using the reservoir simulation model and Majid M. Faskhoodi who combined the first finely-layered reservoir model covering all three reservoirs and studied the effect of different pressure maintenance strategies. Their initial efforts were essential to the work accomplished since and the current achievements. Thanks were extended to Jorge S. Gomes and Gerard Bloch for their kind and thorough review of the manuscript. References SPE 116989 Gomes J.S., M. Ribeiro, S. Neghaban, Y. Dabbour, J. Bahamaish, G. Zaborowski (2006) – The Role of Geomechanics at Early Stages of Field Development: A Case Study. Paper SPE 101425, presented at 12th ADIPEC conference, 5-8 November, Abu Dhabi. Koepnick R.B. (1987) – Distribution and Permeability of Stylolite-bearing Horizons within a Lower Cretaceous Carbonate Reservoir in the Middle East. SPE Formation Evaluation, p.137-142 Marzouk I. and M.A. Sattar (1994) – Wrench Tectonics in Abu Dhabi, United Arab Emirates. In GeoArabia, vol.2, p.655-668. Melville P., O. Al Jeelani, S. Al Menhali, J. Grotsch (2004) – Three-dimensional Seismic Analysis in the Characterization of a Giant Carbonate Field, Onshore Abu Dhabi, United Arab Emirates. 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