Predicting and optimising the mature Windalia waterflood based on a capacitance-resistance model (CRM)

2012 ◽  
Vol 52 (2) ◽  
pp. 656
Author(s):  
Wee Yong Gan ◽  
Lina Hartanto ◽  
Andrew Haynes ◽  
Morteza Sayarpour
Keyword(s):  
Water Injection ◽  
Oil Production ◽  
Operating Conditions ◽  
Significant Heterogeneity ◽  
Well Performance ◽  
Fractional Flow ◽  
Injection Wells ◽  
Resistance Model ◽  
Production Wells ◽  
The Impact

Waterflood development drilling of the Windalia reservoir on Barrow Island at 40-acre spacing started in 1968, using five-spot and nine-spot inverted drive flood patterns. There was a general conversion to line drive in mid-1970 with various infill and realignment projects. The field comprises more than 220 active injectors and 400 producers. The reservoir is geologically complex, with low permeability and significant heterogeneity. Historically, empirical techniques and fractional flow models were used for forecasting, but these approaches have many inherent limitations; for example, they do not provide individual well performance and they are not sensitive to changes in operating conditions. More recently, a capacitance-resistance model (CRM) that uses historical injection and production data has been used to establish long-term behaviours between water injection and oil production wells, including inter-well connectivity, delay time constants and productivity indices. The evaluation of these behaviours allows direct quantification of waterflood efficiency at well-to-well level and improves identification of opportunities for changing injection patterns and prioritisation of operations and well workovers. Optimisation and forecasting of the Windalia waterflood is performed by maximising cumulative oil production by reallocating the available field wide injection water and evaluating individual injection wells target rates. Numerous optimisation scenarios were built into the models to account for the impact of changing operating conditions such as water availability and aging of wells and processing facilities. CRM is robust and is appropriate for simultaneous optimisation of well rates in a field where water injection and oil production wells are shut-in frequently. The PowerPoint presentation is not available to APPEA.

scholarly journals Design method and application of accurate adjustment scheme for water injection wells around adjustment wells

2021 ◽  
Author(s):  
Tongchun Hao ◽  
Liguo Zhong ◽  
Jianbin Liu ◽  
Xiaodong Han ◽  
Tianyin Zhu ◽  
...  
Keyword(s):  
Production Efficiency ◽  
Design Method ◽  
Water Injection ◽  
Oil Field ◽  
Productivity Index ◽  
Injection Wells ◽  
Wellhead Pressure ◽  
Production Wells ◽  
Drilling Operations ◽  
The Impact

AbstractAffected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut-in method is to close all water injection wells around the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method uses water injection index and liquid productivity index as target parameters to analyze the correlation between injection and production wells. Select water injection wells with a high correlation and combine other parameters such as wellhead pressure and pressure recovery speed to design accurate adjustment schemes. Low-correlation wells do not take shut-in measures. This method was applied to 20 infill adjustment wells in the Penglai Oilfield. The correlation between injection and production wells was calculated using the data more than 500 injection wells and production wells. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000 m3. This method achieves accurate adjustment for water injection wells that are high correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.

scholarly journals Streamline simulation study on recovery of oil by water flooding: A real case study on Haripur field

2016 ◽  
Vol 28 (1) ◽  
pp. 61-72
Author(s):  
Mohammad Amirul Islam ◽  
ASM Woobaidullah ◽  
Badrul Imam
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Oil Production ◽  
Water Flooding ◽  
Present Condition ◽  
Optimum Number ◽  
Injection Wells ◽  
Reservoir Performance ◽  
Production Wells ◽  
Head Pressure

Haripur field is the first oil producing field in Bangladesh. The field produced approximately 0.53 MMSTB of oil from the well No. SY-7. The oil production began in 1987 and terminated in 1994. All of the oil was produced by the reservoir own energy from the depth of 2030 meter. Recent investigation and study have revealed that approximately 31 MMSTB Oil is remaining in that formation as validated by the reservoir performance based study i.e. oil production rate and tube head pressure history matching. At present condition, the reservoir has no pressure energy to lift the oil to surface as it requires minimum 1500 psi pressure, so it needs pressure energy to lift the oil to surface. Among the recent developed technologies water injection is one of the best methods to sweep oil towards the production well from the injection well as well as to provide sufficient pressure for lifting. In this study we proposed design for optimum waterflooding pattern and defined optimum number of injection and production wells. In addition the production and injection rates are optimized along with selection of the best placement of production and injection wells and their life.Bangladesh J. Sci. Res. 28(1): 61-72, June-2015

scholarly journals Law and countermeasures for the casing damage of oil production wells and water injection wells in Tarim Oilfield

2011 ◽  
Vol 38 (3) ◽  
pp. 352-361 ◽  
Author(s):  
Wang Tao ◽  
Yang Shenglai ◽  
Zhu Weihong ◽  
Bian Wanjiang ◽  
Liu Min ◽  
...  
Keyword(s):  
Water Injection ◽  
Oil Production ◽  
Injection Wells ◽  
Casing Damage ◽  
Production Wells

The New Generation of Outflow Control Devices Autonomously Controlling the Conformance of Water Injection Well- A Case Study with ADNOC Onshore

2021 ◽  
Author(s):  
Sultan Ibrahim Al Shemaili ◽  
Ahmed Mohamed Fawzy ◽  
Elamari Assreti ◽  
Mohamed El Maghraby ◽  
Mojtaba Moradi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Dynamic Properties ◽  
Short Circuit ◽  
Water Injection ◽  
Performance Outcomes ◽  
Injection Well ◽  
Well Performance ◽  
Injection Wells ◽  
Horizontal Section ◽  
Control Devices

Abstract Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close. Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance. A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained. This paper presents the results from one of the early installations of the valves in a water injection well in the Middle East for ADNOC onshore. The paper discusses the applied completion design workflow as well as some field performance and PLT data.

Oil-Rate Forecast by Inferring Fractional-Flow Models From Field Data With Koval Method Combined With the Capacitance/Resistance Model

2015 ◽  
Vol 18 (04) ◽  
pp. 534-553 ◽  
Author(s):  
Fei Cao ◽  
Haishan Luo ◽  
Larry W. Lake
Keyword(s):  
Field Data ◽  
Oil Production ◽  
Data Driven ◽  
Analytical Models ◽  
Fractional Flow ◽  
Physical Behavior ◽  
Flow Models ◽  
Drainage Volume ◽  
Resistance Model ◽  
Water Cut

Summary Many empirical and analytical models were developed to forecast oil production. Empirical models (including data-driven models) can, for example, find correlations between oil cut and production, but they lack explicit knowledge of the physical behavior. Classic analytical models are loyal to reservoir physics. Nevertheless, they often require estimation of water saturation as a function of time, which is difficult to obtain for multiwell reservoirs. It is desirable to combine advantages of both empirical and analytical models and develop a physical-model-based method that uses field data to infer oil rate. In this paper, we propose to infer fractional-flow models from field data by use of the Koval (1963) theory. We inversely solved the Koval fractional-flow equation to obtain a relationship between water cut and dimensionless time. By history matching field water-cut data, two model parameters, the Koval factor and the producer-drainage volume, are estimated. Nevertheless, it is challenging to use the Koval approach as a predictive model directly because the injection contribution into each producer in a future-time horizon must be evaluated first. To address this issue, we combine the Koval approach with the capacitance/resistance model (CRM), which characterizes the injector/producer connectivities and response time. The material balance of fluids is established in a producer-based drainage volume to consider the contributions from nearby injectors and the time lag in production caused by reservoir/fluids compressibility. A regression approach is simultaneously advanced to minimize the model error. Because of robustly integrating the reservoir physical behavior and the data-driven approach, the combination of the Koval theory and the CRM can result in a synergy that leads to accurate oil-rate predictions. We validated this integrated method in synthetic homogeneous and heterogeneous reservoirs to test its reliability, and further applied it to a field case in western Venezuela. Case studies demonstrate that one can use this integrated model as a real-time tool to characterize interwell connection and to predict future oil production accurately.

scholarly journals Environmental conditions and diffusion-limited microbial transfer drive specific microbial communities detected at different sections in oil-production reservoir with water-flooding

2020 ◽  
Author(s):  
Peike Gao ◽  
Huimei Tian ◽  
Guoqiang Li ◽  
Feng Zhao ◽  
Wenjie Xia ◽  
...  
Keyword(s):  
Microbial Communities ◽  
Water Injection ◽  
Oil Production ◽  
Environmental Variation ◽  
Water Flooding ◽  
Petroleum Reservoir ◽  
Diffusion Limited ◽  
Production Wells ◽  
And Diffusion ◽  
Production Facilities

ABSTRACTThis study investigated the distribution of microbial communities in the oilfield production facilities of a water-flooding petroleum reservoir and the roles of environmental variation, microorganisms in injected water, and diffusion-limited microbial transfer in structuring the microbial communities. Similar bacterial communities were observed in surface water-injection facilities dominated by aerobic or facultative anaerobic Betaproteobacteria, Alphaproteobacteria, and Flavobacteria. Distinct bacterial communities were observed in downhole of the water-injection wells dominated by Clostridia, Deltaproteobacteria, Anaerolineae, and Synergistia, and in the oil-production wells dominated by Gammaproteobacteria, Betaproteobacteria, and Epsilonproteobacteria. Methanosaeta, Methanobacterium, and Methanolinea were dominant archaeal taxa in the water-injection facilities, while the oil-production wells were predominated by Methanosaeta, Methanomethylovorans, and Methanocalculus. Energy, nucleotide, translation, and glycan biosynthesis metabolisms were more active in the downhole of the water-injection wells, while bacterial chemotaxis, biofilm formation, two-component system, and xenobiotic biodegradation was associated with the oil-production wells. The number of shared OTUs and its positive correlation with formation permeability revealed differential diffusion-limited microbial transfer in oil-production facilities. The overall results indicate that environmental variation and microorganisms in injected water are the determinants that structure microbial communities in water-injection facilities, and the determinants in oil-bearing strata are environmental variation and diffusion-limited microbial transfer.IMPORTANCEWater-flooding continually inoculates petroleum reservoirs with exogenous microorganisms, nutrients, and oxygen. However, how this process influences the subsurface microbial community of the whole production process remains unclear. In this study, we investigated the spatial distribution of microbial communities in the oilfield production facilities of a water-flooding petroleum reservoir, and comprehensively illustrate the roles of environmental variation, microorganisms in injected water, and diffusion-limited microbial transfer in structuring the microbial communities. The results advance fundamental understanding on petroleum reservoir ecosystems that subjected to anthropogenic perturbations during oil production processes.

Comparison of Water Treatment Plant and Water Source Well: Field Evaluation of Waterflooding Project in Shushufindi-Aguarico Field

2021 ◽  
Author(s):  
Oki Maulidani ◽  
Veronica Maldonado ◽  
Juan Gallardo ◽  
Victoria Zurita ◽  
Cristian Giol ◽  
...  
Keyword(s):  
Water Treatment ◽  
Water Injection ◽  
Treatment Plant ◽  
Water Reservoir ◽  
Field Evaluation ◽  
Water Treatment Plant ◽  
Water Source ◽  
Operational Cost ◽  
Injection Wells ◽  
Production Wells

Abstract Waterflooding project has been implemented in Shushufindi-Aguarico mature field since late 2014. Having a compatible and cost-effective injected water is one of the key elements to ensure the success of this project. In perspective, water treatment plant was constructed in 2014 during pilot stage while water sources wells were completed in 2019 as an alternative source of injected water at the expansion stage of waterflooding project. This paper presents the comparison between both systems used as part of the water injection strategy: the Water Injection Plant (WIP) and Water Producer Wells (WPW). A complete system of water treatment plant is located in one of the production stations. The process basically starts by collecting water from production wells and workovers then treating it mechanically using a flotation unit and chemically to remove solid as well as oil contents. The water is then injected into injection wells with the help of horizontal pumping system (HPS). In the system of water source wells, two wells were converted to produce water from Hollin water reservoir utilizing electrical submersible pumps (ESP). The water is directly injected without any treatment into injection wells given the analysis of its fluid properties. The initial investment for water treatment plant is four times compared to water source well providing equal injection capacity where the operational cost per barrel of injected water is similar. The operational cost for water treatment plant refers to surface facilities maintenance and daily chemical consumption while for water source well it refers to associated cost of ESP reparation and workover operation. The average run-life of the water source wells in Ecuador Oriente basin is 1,200 days. The biggest challenge of water treatment plant is dealing with solid content whereas for water source well is on how to ensure integrity of the well and the flowline system in the high temperature and CO2 environment. Continuous improvements have been performed to address these challenges such as chemical treatment adjustments, real-time surveillance of injection wells, and modification of flowline system. Water treatment plant not only provides compatible water for injection wells but also supports water handling capacity as it utilizes water from production wells. In the other hand, compatible and clean water from Hollin water reservoir is the main benefit of water source wells. This paper will outline the pros and cons of water treatment plant and water source well based on field evaluation in Shushufindi-Aguarico field. It outlines the operational experience and lessons learned that can be used as a guide and reference when evaluating water sources for a waterflooding strategy. Economical analysis as well as continuous improvement will also be presented in this paper to deliver an integrated analysis.

Horizontal Water Injection Wells: Injectivity and Containment of Injection-Induced Fractures

2021 ◽  
Author(s):  
Jongsoo Hwang ◽  
Mukul Sharma ◽  
Maria-Magdalena Chiotoroiu ◽  
Torsten Clemens
Keyword(s):  
Horizontal Well ◽  
Water Injection ◽  
Fracture Initiation ◽  
Horizontal Stress ◽  
Operating Conditions ◽  
Critical Factors ◽  
Injection Wells ◽  
Stress Direction ◽  
Maximum Horizontal Stress ◽  
Transverse Fractures

Abstract Horizontal water injection wells have the capacity to inject larger volumes of water and have a smaller surface footprint than vertical wells. We present a new quantitative analysis on horizontal well injectivity, injection scheme (matrix vs. fracturing), and fracture containment. To precisely predict injector performance and delineate safe operating conditions, we simulate particle plugging, thermo-poro-elastic stress changes, thermal convection and conduction and fracture growth/containment in reservoirs with multiple layers. Simulation results show that matrix injection in horizontal wells continues over a longer time than vertical injectors as the particle deposition occurs slowly on the larger surface area of horizontal wellbores. At the same time, heat loss occurs uniformly over a longer wellbore length to cause less thermal stress reduction and delay fracture initiation. As a result, the horizontal well length and the injection rates are critical factors that control fracture initiation and long-term injectivity of horizontal injectors. To predict fracture containment accurately, thermal conduction in the caprock and associated thermal stresses are found to be critical factors. We show that ignoring these factors underestimates fracture height growth. Based on our simulation analysis, we suggest strategies to maintain high injectivity and delay fracture initiation by controlling the injection rate, temperature, and water quality. We also provide several methods to design horizontal water injectors to improve fracture containment considering wellbore orientation relative to the local stress orientations. Well placement in the local maximum horizontal stress direction induces longitudinal fractures with better containment and less fracture turning than transverse fractures. When the well is drilled perpendicular to the maximum horizontal stress direction, the initiation of transverse fractures is delayed compared with the longitudinal case. Flow control devices are recommended to segment the flow rate and the wellbore. This helps to ensure uniform water placement and helps to keep the fractures contained.

Development of Tight Upper Cretaceous Reservoir in Offshore Black Sea Adds Life to a Mature Asset

2021 ◽  
Author(s):  
I. Mitrea ◽  
R. Cataraiani ◽  
M. Banu ◽  
S. Shirzadi ◽  
W. Renkema ◽  
...  
Keyword(s):  
Black Sea ◽  
Upper Cretaceous ◽  
Rock Physics ◽  
Oil Production ◽  
Economic Life ◽  
Production Performance ◽  
Single Fracture ◽  
Well Performance ◽  
Acoustic Image ◽  
The Impact

Abstract This Upper Cretaceous reservoir, a tight reservoir dominated by silt, marl, argillaceous limestone and conglomerates in Black Sea Histria block, is the dominant of three oil-producing reservoirs in Histria Block. The other two, Albian and Eocene, are depleted, and not the focus of field re-development. This paper addresses the challenges and opportunities that were faced during the re-development process in this reservoir such as depletion, low productivity areas, lithology, seismic resolution, and stimulation effectiveness. Historically, production from Upper Cretaceous wells could not justify the economic life of the asset. As new fracturing technology evolved in recent years, the re-development focused on replacing old, vertical/deviated one-stage stimulations low producing wells with horizontal, multi-stage hydraulic fractured wells. The project team integrated various disciplines and approaches by re-processing old seismic to improve resolution and signal, integrating sedimentology studies using cores, XRF, XRD and thin section analysis with petrophysical evaluation and quantitative geophysical analyses, which then will provide properties for geological and geomechanical models to optimize well planning and fracture placement. Seven wells drilled since end of 2017 to mid-2021 have demonstrated the value of integration and proper planning in development of a mature field with existing depletion. Optimizing the well and fracture placement with respect to depletion in existing wells resulted in accessing areas with original reservoir pressure, not effectively drained by old wells. Integrating the well production performance with tracer results from each fractured stage, and NMR/Acoustic images from logs enhanced the understanding of the impact of lithofacies on stimulation. This has allowed better assessment and prediction of well performance, ultimately improving well placement and stimulation design. The example from this paper highlights the value of the integrating seismic reprocessing, attribute analysis, production technology, sedimentology, cuttings analysis and quantitative rock physics in characterizing the heterogeneity of the reservoir, which ultimately contributed to "sweet spot" targeting in a depleted reservoir with existing producers and deeper understanding of the development potential in Upper Cretaceous. The 2017-2021 wells contribute to more than 30 percent of the total oil production in the asset and reverse the decline in oil production. In addition, these wells have two to four times higher initial rates because of larger effective drainage area than a single fracture well. Three areas of novelty are highlighted in this paper. The application of acoustic image/NMR logging to identify lithofacies and optimize fracturing strategy in horizontal laterals. The tracers analysis of hydraulic fracture performance and integration with seismic and petrophysical analysis to categorize the productivity with rock types. The optimization of fracture placement considering the changes of fluid and proppant volumes without compromising fracture geometries and avoiding negative fracture driven interactions by customized pumping approach.

Challenges from Well Shut-in Amid the Oil Downturn: Long Term Impacts on Near Wellbore Skin Buildup and Sand Control

2021 ◽  
Author(s):  
Mohammad Soroush ◽  
Mahdi Mahmoudi ◽  
Morteza Roostaei ◽  
Hossein Izadi ◽  
Seyed Abolhassan Hosseini ◽  
...  
Keyword(s):  
Hot Spot ◽  
Oil Production ◽  
Well Performance ◽  
Well Completion ◽  
Flow Control Devices ◽  
Sand Control ◽  
Control Devices ◽  
Inflow Problem ◽  
The Impact

Abstract In wake of the biggest oil crash in history triggered by the COVID-19 pandemic; Western Canada in- situ production is under tremendous price pressure. Therefore, the operators may consider shut in the wells. Current investigation offers an insight into the effect of near-wellbore skin buildup because of such shut-in. A series of simulation studies was performed to quantitatively address the impact of well shut-in on the long-term performance of well, in particular on key performance indicators of the well including cumulative steam to oil ratio and cumulative oil production. The long-term shut-in contributes to three main modes of plugging: (1) near-wellbore pore plugging by clays and fines, (2) scaling, and (3) chemical consolidation induced by corrosion. A series of carefully designed simulations was also utilized to understand the potential of skin buildup in the near-wellbore region and within different sand control devices. The simulation results showed a higher sensitivity of well performance to shut-in for the wells in the initial stage of SAGD production. If the well is shut in during the first years, the total reduction in cumulative oil production is much higher compared to a well which is shut-in during late SAGD production life. As the induced skin due to shut-in increases, the ultimate cumulative oil production drops whose magnitude depends on well completion designs. The highest effect on the cumulative oil production is in the case of completion designs with flow control devices (liner deployed and tubing deployed completions). Therefore, wellbore hydraulics and completion design play key roles in the maintenance of uniform inflow profile, and the skin buildup due to shut-in poses a high risk of inflow problem and increases the risk of hot-spot development and steam breakthrough. This investigation offers a new understanding concerning the effect of shut-in and wellbore skin buildup on SAGD operation. It helps production and completion engineers to better understand and select candidate wells for shut-in and subsequently to minimize the skin buildup in wells.

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