Ingenious Method for Water Injection Optimization on Mature Carbonate Reservoir with Rapid Pressure Decline Problem, Case Study: XJN Field - South Sumatra, Indonesia

Abstract XJN field has implemented water injection as pressure maintenance since 1987, only one year after initial production. XJN is carbonate reservoir with weak aquifer underlying the oil zone. Initial reservoir pressure was 2,700 psi and peak production was 27,000 BOPD. Reservoir pressure was drop to 1,800 psi within 5 years of production. During 1991-2007, better injection management was performed to provide negative voidage. This action has managed to bring reservoir pressure back to its initial pressure, eventually enabling all wells to be converted from gaslift to naturalflow. In 2013, watercut has increased to 97% and several naturally flowing wells began to ceased-to-flow, then production mode was changed gradually from naturalflow to artificial lift using Electric Submersible Pump (ESP). In 2017-2020, there was rapid reservoir pressure decline around 300 psi/year while XJN water injection performance considered flawless. Voidage Replacement Ratio (VRR) was 1.3, but reservoir pressure was kept declining. This situation will cause ESP pump off on producer wells which in turn means big production loss. This paper will elaborate about the simple-uncommon-yet effective methods for problem detection and its solution to revive pressure and production. Analysis was began with observing the deviation of VRR and reservoir pressure, this was to estimate "leak" time of water injection. Next analysis was evaluation of injection rate leak off using material balance with reverse history matching. Reverse here means making reservoir pressure as main constraint rather than history matching goal. After that, it was continued with water injection flow path analysis. This was done by plotting production-injection-pressure data then make several small groups of injector-producer based on visible relationships. The purposes were to find key injector wells and to shut-in all inefficient ones. Furthermore, injection re-distribution was also performed based on VRR calculation on groups from previous step, water distribution priority was focused on key injector wells. These analysis have also paved the way for searching channeling possibility on injector wells. The results, XJN reservoir pressure showed an increasing trend of 100 psi/year after optimization was performed, with current pressure around 2000 psi. The increase in reservoir pressure has also made it possible to optimize ESP, field lifting has increased for 5000 BLPD. This project has also successfully secured XJN remaining oil. This project was racing with rapid pressure decline that will lead to early ESP pump off and production loss. The integrated subsurface analytical methods and actions being taken were simple but effective. Close monitoring on reservoir pressure, water injection and ESP parameters will be needed as field surveillance. Integrated analysis with surface facility engineering should also be carried out in the future in regards to surface network, injection rate and reservoir pressure.

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Injection-production optimization of carbonate reservoir based on an inter-well connectivity model

Energy Exploration & Exploitation ◽

10.1177/0144598721994653 ◽

2021 ◽

pp. 014459872199465

Author(s):

Yuhui Zhou ◽

Sheng Lei ◽

Xuebiao Du ◽

Shichang Ju ◽

Wei Li

Keyword(s):

History Matching ◽

Water Injection ◽

Field Application ◽

Carbonate Reservoir ◽

Production Optimization ◽

Oil Field ◽

Carbonate Reservoirs ◽

Utilization Rate ◽

Production Volume ◽

Connectivity Model

Carbonate reservoirs are highly heterogeneous. During waterflooding stage, the channeling phenomenon of displacing fluid in high-permeability layers easily leads to early water breakthrough and high water-cut with low recovery rate. To quantitatively characterize the inter-well connectivity parameters (including conductivity and connected volume), we developed an inter-well connectivity model based on the principle of inter-well connectivity and the geological data and development performance of carbonate reservoirs. Thus, the planar water injection allocation factors and water injection utilization rate of different layers can be obtained. In addition, when the proposed model is integrated with automatic history matching method and production optimization algorithm, the real-time oil and water production can be optimized and predicted. Field application demonstrates that adjusting injection parameters based on the model outputs results in a 1.5% increase in annual oil production, which offers significant guidance for the efficient development of similar oil reservoirs. In this study, the connectivity method was applied to multi-layer real reservoirs for the first time, and the injection and production volume of injection-production wells were repeatedly updated based on multiple iterations of water injection efficiency. The correctness of the method was verified by conceptual calculations and then applied to real reservoirs. So that the oil field can increase production in a short time, and has good application value.

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First Successful Proppant Frac in a Water Injection Field Strategy, West Qurna-1, South Iraq

10.2118/205240-ms ◽

2022 ◽

Author(s):

Erfan Mustafa Al lawe ◽

Adnan Humaidan ◽

Afolabi Amodu ◽

Mike Parker ◽

Oscar Alvarado ◽

...

Keyword(s):

Water Injection ◽

Injection Rate ◽

Fracture Model ◽

Productivity Index ◽

Base Line ◽

Reservoir Pressure ◽

Injection Strategy ◽

Injection Test ◽

Step Rate ◽

Step Down

Abstract Zubair formation in West Qurna field, is one of the largest prolific reservoirs comprising of oil bearing sandstone layers interbedded with shale sequences. An average productivity index of 6 STB/D/psi is observed without any types of stimulation treatment. As the reservoir pressure declines from production, a peripheral water injection strategy was planned in both flanks of the reservoir to enhance the existing wells production deliverability. The peripheral injection program was initiated by drilling several injectors in the west flank. Well A1 was the first injector drilled and its reservoir pressure indicated good communication with the up-dip production wells. An injection test was conducted, revealing an estimated injectivity index of 0.06 STB//D/psi. Candidate well was then re-perforated and stimulated with HF/HCl mud acid, however no significant improvement in injectivity was observed due to the complex reservoir mineralogy and heterogeneity associated to the different targeted layers. An extended high-pressure injection test was performed achieving an injectivity index of 0.29 STB/D/psi at 4500 psi. As this performance was sub-optimal, a proppant fracture was proposed to achieve an optimal injection rate. A reservoir-centric fracture model was built, using the petrophysical and geo-mechanical properties from the Zubair formation, with the objective of optimizing the perforation cluster, fracture placement and injectivity performance. A wellhead isolation tool was utilized as wellhead rating was not able to withstand the fracture model surface pressure; downhole gauges were also installed to provide an accurate analysis of the pressure trends. The job commenced with a brine injection test to determine the base-line injectivity profile. The tubing volume was then displaced with a linear gel to perform a step-rate / step-down test. The analysis of the step-rate test revealed the fracture extension pressure, which was set as the maximum allowable injection pressure when the well is put on continuous injection. The step-down test showed significant near wellbore tortuosity with negligible perforation friction. A fracture fluid calibration test was then performed to validate the integrated model leak-off profile, fracture gradient and young’s modulus; via a coupled pressure fall-off and temperature log analysis. Based on the fluid efficiency, the pad volume was adjusted to achieve a tip screen-out. The job was successfully pumped and tip screen-out was achieved after pumping over ~90% of the planned proppant volume. A 7 days post-frac extended injection test was then conducted, achieving an injection rate of 12.5 KBWD at 1300 psi with an injectivity index of 4.2 STB/D/psi. These results proved that the implementation of a reservoir-centric Proppant Fracture treatment, can drastically improve the water injection strategy and field deliverability performance even in good quality rock formations. This first integrated fracture model and water injection field strategy, represents a building platform for further field development optimization plans in Southern Iraq.

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The Perspective of Novel Chemical Tracer Technology in Reservoir Surveillance and Hydrodynamic Modelling for More Efficient Hydrocarbon Recovery

10.2118/205678-ms ◽

2021 ◽

Author(s):

Nadir Husein ◽

Evgeny Aleksandrovich Malyavko ◽

Ruslan Rashidovich Gazizov ◽

Anton Vitalyevich Buyanov ◽

Aleksey Aleksandrovich Romanov ◽

...

Keyword(s):

Oil Recovery ◽

Continuous Production ◽

Economic Effect ◽

Water Injection ◽

Injection Rate ◽

Reservoir Pressure ◽

Entire Area ◽

Field Development ◽

Oil Companies ◽

Maintenance System

Abstract Today, efficient field development cannot be managed without proper surveillance providing oil companies with important geological and engineering information for prompt decision-making. Once continuous production is achieved, it is necessary to maintain a consistently high level of oil recovery. As a rule, a reservoir pressure maintenance system is extensively implemented for this purpose over the entire area because of decreasing reservoir pressure. At the same time, it is important to adjust the water injection to timely prevent water cut increasing in production wells, while maintaining efficient reservoir pressure compensation across the field. That is why it is necessary to have a relevant inter-well hydrodynamic model as well as to quantify the water injection rate. There are many ways to analyse the efficiency of the reservoir pressure maintenance system, but not all of them yield a positive, and most importantly, a reliable result. It is crucial that extensive zonal production surveillance efforts generate a significant economic effect and the information obtained helps boost oil production. Thus, the main objective of this paper is to identify a method and conduct an effective study to establish the degree of reservoir connectivity and quantify the inter-well parameters of a low permeability tested field.

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Characterization of Reservoir Heterogeneity Through Fluid Movement Monitoring With Deep Electromagnetic and Pressure Measurements

SPE Reservoir Evaluation & Engineering ◽

10.2118/116328-pa ◽

2010 ◽

Vol 13 (03) ◽

pp. 509-522 ◽

Cited By ~ 2

Author(s):

Lang Zhan ◽

Fikri Kuchuk ◽

Ali M. Al-Shahri ◽

S. Mark Ma ◽

T.S.. S. Ramakrishnan ◽

...

Keyword(s):

History Matching ◽

Water Injection ◽

Electrode Array ◽

Vertical Direction ◽

Time Lapse ◽

Carbonate Reservoir ◽

Salt Transport ◽

Local Formation ◽

Primary Finding

Summary This paper presents a novel technique to characterize detailed formation heterogeneity for a carbonate reservoir using measurements from electrode resistivity array (ERA), a wireline formation tester, and a permanent downhole pressure sensor. The ERA was installed on tubing in a barefoot well rather than permanently cemented outside the casing as in previous applications. This notable difference provided flexibility for device installation and operation but also introduced particular issues in the ERA data acquisition and interpretation. Furthermore, the ERA measurements were carried out in conjunction with low-salinity water injection and oil and water production in the same well. The primary finding presented in this paper is that the time-lapse ERA voltages near a source electrode showed unique characteristics that represented local formation heterogeneity. This localized sensitivity of ERA data allows detailed characterization of the formation heterogeneity within the length of the ERA string in the vertical direction and about 100 ft laterally around the wellbore. The scale size of the investigated formation heterogeneity is comparable to typical grid sizes used in current reservoir simulations. Models were developed to identify stratified permeability heterogeneities from the time-lapse ERA voltages. The stratified heterogeneity estimated from the ERA measurements was compared to and verified by openhole logs and core analyses data. The final heterogeneous reservoir model from the ERA was subsequently applied to a numerical simulation that integrated the dynamic fluid flow, salt transport, and electrode array responses for monitoring water-front movement and estimating multiphase formation properties. The history matching of the time-lapse ERA data confirmed the first pass estimates of the identified heterogeneities.

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Peramalan Kinerja Lapangan SNP Dengan Injeksi Air Menggunakan Metode Material Balance

Journal of Earth Energy Science, Engineering, and Technology ◽

10.25105/jeeset.v1i3.4683 ◽

2018 ◽

Vol 1 (3) ◽

Author(s):

Andre Albert Sahetapy Engel ◽

Rachmat Sudibjo ◽

Muhammad Taufiq Fathaddin

Keyword(s):

Oil And Gas ◽

Water Injection ◽

Material Balance ◽

Oil And Gas Industry ◽

Reservoir Pressure ◽

Injection Wells ◽

Gas Industry ◽

Evaluation Result ◽

Cumulative Production ◽

The Common

<p>The decline in production from of a field is the common problem in the oil and gas industry. One of the causes of the decrease in production is the decline of reservoir pressure. Based on the analisis result, it was found that SNP field had a weak water drive. The most dominant drive of the field was fluid expansion. In order to reduce the problem, a reservoir pressure maintenance effort was required by injecting water. In this research, the effect of water injection to reservoir pressure and cumulative production was analyzed. From the evaluation result, it was found that the existing inejection performance using one injection well to Zones A and B was not optimum. Because, the recovery factor was predicted to 29.11% only.By activating the four injection wells, the recoverty factor could be increase to 31.43%.</p>

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Implementation and Intermediate Monitoring Outcomes of the First Commingled Up-Dip SMART Water Injection Well in PA-B Platform Piltun-Astokhskoye Offshore Oil and Gas Field

10.2118/206503-ms ◽

2021 ◽

Author(s):

Alexander Vitalyevich Tsarenko ◽

Valentin Nikolaevich Tarsky ◽

Lisa Jane Robson

Keyword(s):

Oil And Gas ◽

Water Injection ◽

Surveillance Data ◽

Integrated Analysis ◽

Reservoir Pressure ◽

Gas Field ◽

Smart Water ◽

Oil And Gas Field ◽

Offshore Oil And Gas ◽

Offshore Oil

Abstract The objective of this article is to share an evaluation of the background, drilling outcomes and production and reservoir pressure impacts from two years of monitoring the first commingled up-dip SMART water injector drilled in the Piltun area of the Piltun-Astokhskoye offshore oil and gas field, located in Sakhalin, far east of Russia. The unique aspect of this water injector is that it was drilled into the up-dip gas caps of two separate reservoirs to provide pressure support to commingled oil producers, complementing the down-dip water injectors already in place. This article highlights some details of the well maturation decisions and expectations based on output of the dynamic modelling studies. Drilling outcomes and well performance is compared to expectations. Initial results of the surveillance programme and field data analysis based on a two-year monitoring period are discussed to show intermediate outcomes of up-dip water injection in the Piltun area. Finally, remaining questions and uncertainties are shared. Piltun-Astokhskoye is a complex multi-reservoir offshore oil and gas field with sizeable gas caps, significant heterogeneity both between and within reservoirs and a complex production history involving commingled oil producers and water injectors. Limited data is available to assess the impact of development decisions. Integrated analysis using multiple data sources and back-to-basics geology and reservoir engineering is required to understand how the reservoirs are responding to up-dip water injection, in order to predict future performance and make informed decisions to optimise the Piltun development over the long term. Surveillance data shows that up-dip water injection is effective in increasing reservoir pressure and oil recovery in one of the reservoirs, whilst having little impact on the other. Analysis shows that variable impact is due to the influence of gas cap size on up-dip water injection efficiency and the risk of trapped gas volumes due to water injection into the gas cap. The importance of integration between different sources of surveillance data and analytical tools to complete a comprehensive and reliable analysis is shown.

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Lessons Learned From Energy Models: Iraq's South Rumaila Case Study

SPE Reservoir Evaluation & Engineering ◽

10.2118/105131-pa ◽

2008 ◽

Vol 11 (04) ◽

pp. 759-767 ◽

Cited By ~ 2

Author(s):

C. Shah Kabir ◽

Nidhal I. Mohammed ◽

Manoj K. Choudhary

Keyword(s):

Finite Difference ◽

History Matching ◽

Flow Behavior ◽

Finite Difference Methods ◽

Water Injection ◽

Material Balance ◽

Reservoir Management ◽

Lessons Learned ◽

Full Field ◽

Numeric Modeling

Summary Understanding reservoir behavior is the key to reservoir management. This study shows how energy modeling with rapid material-balance techniques, followed by numerical simulations with streamlines and finite-difference methods, aided understanding of reservoir-flow behavior. South Rumaila's long and elongated Zubair reservoir experiences uneven aquifer support from the western and eastern flanks. This uneven pressure support prompted injection in the weaker eastern flank to boost reservoir energy. We learned that aquifer influx provided nearly 95% of the reservoir's energy in its 50-year producing life, with water injection contributing less than 5% of the total energy supply. The west-to-east aquifer energy support is approximately 29:1, indicating the dominance of aquifer support in the west. Streamline simulations with a 663,000-cell model corroborated many of the findings learned during the material-balance phase of this study. Cursory adjustments to aquifer properties led to acceptable match with pulse-neutron capture or PNC-derived-time-lapse oil/water contact (OWC) surfaces. This global-matching approach speeded up the history-matching exercise in that performance of most wells was reproduced, without resorting to local adjustments of the cell properties. The history-matched model showed that the top layers contained the attic oil owing to lack of perforations. Lessons learned from this study include the idea that the material-balance work should precede any numerical flow-simulation study because it provides invaluable insights into reservoir-drive mechanisms and integrity of various input data, besides giving a rapid assessment of the reservoir's flow behavior. Credible material-balance work leaves very little room for adjustment of original hydrocarbons in place, which constitutes an excellent starting point for numerical models. Introduction Before the advent of widespread use of computers and numeric simulators, material-balance (MB) studies were the norm for reservoir management. In this context, Stewart et al. (1954), Irby et al. (1962), and McEwen (1962) presented useful studies. Most popular MB methods include those of Havlena and Odeh (1963), Campbell and Campbell (1978), and Tehrani (1985), among others. Pletcher (2002) provides a comprehensive review of the available MB techniques. In the modern era, classical MB studies seldom precede a full-field numeric modeling, presumably because MB is implicit in this approach. Nonetheless, we think valuable lessons can be learned from analytic MB studies at a fraction of time needed for detailed numeric modeling, preceded by geologic modeling. Of course, the value and amount of information derived from a multicell numeric model cannot be compared to a single-cell MB model. But, an analytic MB study can be an excellent precursor to any detailed 3D modeling effort. Although this point has been made by others (Dake 1994; Pletcher 2002), practice has, however, lagged conventional wisdom. In this paper, we attempt to show the value of a zero-dimensional MB study prior to doing detailed 3D numeric modeling, using both streamline and finite-difference methods. Streamline simulations speeded up the history-matching effort by a factor of three. However, we used the finite-difference approach in prediction runs for its greater flexibility in invoking various producing rules. Initially, the MB study provided key learnings about gross reservoir behavior very rapidly. In particular, energy contributions made by different drive mechanisms, such as uneven natural water influx and water injection, were of great interest for ongoing reservoir-management activities. Estimating in-place hydrocarbon volume and relative strength of the aquifer in the western and eastern flanks constituted key objectives of this study segment. Following the MB segment of the study, we pursued full-field match of historical data (pressure and OWC) with a streamline flow simulator to take advantage of rapid turnaround time. Thereafter, prediction runs were made with the finite-difference model to answer the ongoing water-injection question in the eastern flank of the reservoir. We learned that water injection should be turned off for improved sweep, leading to increased ultimate oil recovery. In addition, the numeric models identified the presence of remaining oil in the attic for future exploitation.

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An Enhanced Cost-Effective Approach for WI Optimization Implemented in a Giant Carbonate Reservoir Undergoing a Transition Scheme from Peripheral to Pattern Injection

10.2118/203781-ms ◽

2021 ◽

Author(s):

Maryvi Martinez ◽

Jhon Ortiz ◽

Fatmah Alshehhi ◽

Bhanu Bethapudi ◽

Krisna Permana ◽

...

Keyword(s):

Task Force ◽

Water Injection ◽

Material Balance ◽

Reservoir Management ◽

Carbonate Reservoir ◽

Maintenance Cost ◽

Water Handling ◽

Short Period ◽

The Impact ◽

Successful Integration

Abstract With the aim to fulfil a more comprehensive and effective water injection optimization strategy in a giant carbonate reservoir, the asset carried out a dedicated study for a giant carbonate unit (Unit-M) to evaluate the specific challenges and define mitigation actions to improve the reservoir performance. This paper outlines the experience of the successful integration and strong collaborative environment between Reservoir Management Surveillance-Studies, Water Handling, Optimization and Production Operations teams through the project execution leading to optimal solutions in a short period, in accordance with a long-term plan oriented to effectively manage future injection requirements. These actions allowed a favorable impact on the operating costs associated to the new and more efficient water balancing. Water injection, oil production, and reservoir pressure performance in addition to surveillance data for Unit-M have been analyzed at region and well scale. A better-detailed understanding about Peripheral and pattern injection Balance using streamline simulation and material balance analysis provided the support to implement actions that include: reactivation of the pilot pattern WI wells, redistribution of Water Injection in the periphery, maximize the efficiency of the Water injectors (Roll Up, re-utilization in other units, P&A) and Optimize clusters utilization. Moreover, the reservoir simulation was used to verify the impact of the new Water Injection strategy in pressure maintenance, sweep efficiency and the ultimate recovery expected. The conformation of a dedicated task force team between Water Handling Operations and Development teams enable the alignment to common goals and a successful integration that led to define short term actions and mitigate present challenges of waterflood reservoir management. Effective and timely application of these solutions resulted in significant reduced maintenance cost (+/-30%) of the wells and clusters involved.

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Achieving Injectivity Optimization and Zonal Rates Allocation through Multi-Zone Intelligent Completion Technology – A Field B Case Study from Offshore Malaysia

10.2118/201044-ms ◽

2021 ◽

Author(s):

Fuziana Tusimin ◽

Latief Riyanto ◽

Nurul Aula A'akif Fadzil ◽

Nur Syazana Sadan ◽

Asba Mazidah Abu Bakar ◽

...

Keyword(s):

Real Time ◽

Pressure Support ◽

Water Injection ◽

Injection Rate ◽

Fluid Distribution ◽

Successful Implementation ◽

Reservoir Pressure ◽

Well Completion ◽

Ic Technology

Abstract Properly distributing injected fluid to provide injection conformance and reservoir pressure support into the respective zones of interest in mature fields can be challenging. This challenge, with injection fluid distribution, is typically encountered in fields with high contrast in permeability, reservoir pressure, and injectivity indexes among individual zones. Deployment of intelligent completion (IC) technology to address this challenge has rapidly increased, especially in multi-zone water injector wells, due to its capabilities for real-time reservoir monitoring and control of the fluid injected into multiple zones without requiring well interventions. This paper presents a case study of successful installation of IC technology in two water injector wells in Field B offshore Sarawak. The main objective of the IC implementation is to provide an efficient water-injection method for pressure support to the nearby oil producers and counteract the gas expansion through water injection at the flank area. Water injection implementation using the IC approach can further develop the oil rims and improve oil recovery in the particular reservoir to extend the field's production life. The custom tailored inflow control valve (ICV) design is robust enough to provide control of desired zonal injection rates. Each well was installed with two sets of ICVs to control the injection rate for each dedicated zone as well as a real-time permanent downhole gauge (PDG) to monitor the pressure drop across the ICV for zonal rates allocation / analysis. Apart from conceptual and detailed engineering study of the applied IC technology, proper downhole equipment selection and integration with surface facilities are also crucial to ensure successful implementation of the IC system as a holistic solution to achieve the injection objective. Post well completion installation, a water injectivity test was performed in both the selective and commingle injection modes. During selective injection testing, different positions of the ICV were manipulated and the water injection rate was monitored. This testing approach was performed for each ICV in the well. Post selective injection testing, commingle testing was conducted at the base 9,000 bwpd and maximum injection target of 18,000 bwpd, in which the testing was successfully executed to achieve the maximum well target injection rate. This paper shall discuss the reservoir management strategy through deployment of the water injectors, conceptual well completion design, and multi-zone injectivity requirements. Details such as ICV design using pre-drill and post-drill information, final well completion strategy, pre-installation preparation, installation optimization, execution of the IC deployment, injectivity test procedure, and results are discussed as well.

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Water-Injection Optimization for a Complex Fluvial Heavy-Oil Reservoir by Integrating Geological, Seismic, and Production Data

SPE Reservoir Evaluation & Engineering ◽

10.2118/110492-pa ◽

2009 ◽

Vol 12 (06) ◽

pp. 865-878 ◽

Cited By ~ 3

Author(s):

Xin Feng ◽

Xian-Huan Wen ◽

Bo Li ◽

Ming Liu ◽

Dengen Zhou ◽

...

Keyword(s):

Heavy Oil ◽

Water Injection ◽

Oil Production ◽

Injection Rate ◽

Production Data ◽

Oil Reservoir ◽

Reservoir Pressure ◽

Channel Geometry ◽

Heavy Oil Reservoir ◽

Complex Channel

Summary BZ25-1s field in Bohai Bay, China, is characterized as a complex channelized fluvial reservoir in which small meandering channels were deposited at different geological times stacking and cross cutting each other. There are many isolated small reservoir systems following channel distributions. Early production showed steep pressure and production decline. Quick implementation of water injection was needed to arrest the fast production decline and to stabilize reservoir pressure. While designing the water-injection plan, we faced a number of challenges, such as high oil viscosity (˜200 cp), strong heterogeneity, poor reservoir connectivity, complex channel geometry, and irregular well patterns. A workflow integrating geological, well-log, seismic, and dynamic production data was developed to optimize a water injection plan for this field after a short production history. Focuses of this workflow are the selection of injection wells (converted from existing producers), timing of water injection, and the optimization of injection rates. Following the workflow, the optimal water-injection design for the areas around Platforms D and E was developed and quickly implemented within the first year of production. We started with a relatively small water-injection rate and gradually increased the injection rate to avoid the fast water breakthrough and yet to limit the pressure-decline rate. The responses from the water injection were very positive and resulted in stable reservoir pressure and increase of oil production. Before water injection, the production-decline rates were 26 and 47% in Platforms D and E, respectively. After 1 year of water injection, oil-production-decline rates in these two platforms were reduced to 19 and 14%, respectively. The responses of water injection for different well groups were analyzed in a timely fashion and adjustments to injection/production strategies were implemented accordingly. New information revealed from the water-injection response analysis was used to update the geological model to reduce the model uncertainty, as well as to adjust the water-injection strategies for better sweep efficiency. Our experiences showed that such dynamic adjustment of injection and production schedule is very important to achieve better water-injection efficiency for this heavy-oil reservoir with complex channel geometry.

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