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 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.

OPTIONS OF PULSE NON-STATIONARY WATER FLOODING IN BLOCK SYSTEMS OF DEVELOPMENT

2017 ◽  
pp. 99-103 ◽  
Author(s):  
M. Ya. Habibullin ◽  
R. I. Suleymanov ◽  
L. Z. Zaynagalina ◽  
V. A. Petrov
Keyword(s):  
Water Injection ◽  
Filtration Velocity ◽  
Maximum Distance ◽  
Water Flooding ◽  
Relative Location ◽  
Single Group ◽  
Injection Wells ◽  
Cutting Line ◽  
Mode Of Operation ◽  
Production Wells

In the block systems of water flooding the features of relative location of injection and production wells allow for the variety of options for changing the mode of operation (single, group, block, etc.). The greatest overall effect of the change in filtration velocity at the cutting line, and hence also the effect of pulsed non-stationary flooding, is achieved by alternate stopping of wells. The maximum distance between the injection wells, the mode of operation of which can be changed at the same time, is limited by the duration of the stop and subsequent water injection. Thus, if the duration of half cycles is the same, then this ratio is equal to two, that is the wells in a row should be stopped through one row.

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

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.

Alternative Method of Assessing Optimum Number of Water Injection and Infill Wells in a Field Development Plan

2021 ◽  
Author(s):  
M. Fitri Ramli ◽  
M. Shahrul M. Long ◽  
Amol Nivrutti Pote ◽  
Khairul Azri Ishak
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Net Present Value ◽  
Water Injection ◽  
Numerical Approach ◽  
Development Plan ◽  
Alternative Methods ◽  
Optimum Number ◽  
Injection Wells ◽  
Field Development

Abstract This paper discusses the workflow and method of selecting optimum number of infill and injection wells based on incremental recovery. Normally, for infill wells study, a ‘creaming curve’ method is used to evaluate the optimum number of wells against incremental recovery from the field. However, in the case of determining number of infill wells together with water injection wells, a more comprehensive approach is needed. One needs to evaluate the pressure depletion rate from existing and infill wells together with the dynamic of the producer-injector pairings as well as the sweeping factor. The paper is based on infill and water injection development plan for a brown field in Sabah basin which located in Malaysia. To maintain operatability of the field in the future, several new infill and water injection wells options are evaluated for optimum field life oil production. Unlike infill or producer-only assessment, the same ‘creaming curve’ approach for combination of infill and water injection wells is less effective as large number of simulation runs are needed to sample the combination of these wells that generate optimum oil recovery. This has proven to be challenging especially when the models are large which is normally the case for brown fields and it requires extensive computational hours. In the first part, a modified approach bringing some pre-analytic assessment of producer-injector pairing is being used. The pairings are first ranked based on streamlines visualization, drainage tables and their respective contributions towards oil recovery. The ‘creaming curve’ is then built based on the highest contribution as well as the sequencing of the pairings. The second method mentioned in this paper is the numerical approach through multi-objective optimization using assisted history matching and uncertainty tool. With the help of optimizer, the number of simulation runs can be drastically reduced when only best combination of infills and injectors for each total number of wells are considered. Both alternative methods will be compared with the full computational runs, sampling every single combination of wells. Finally, the optimum number of wells with the combination of infill and water injection wells are analysed based on cumulative oil recovery against the Net Present Value (NPV). This case study therefore demonstrates how alternative methods can be used to resolve the optimum number of infill and water injection wells to avoid lengthy and very large numbers of simulation runs.

scholarly journals Skenario Pengembangan Untuk Meningkatkan Recovery Factor Pada Lapangan TR Lapisan X Dengan Menggunakan Simulasi Reservoir

PETRO ◽  
2018 ◽  
Vol 4 (4) ◽  
Author(s):  
Muhamad Taufan Azhari
Keyword(s):  
Reservoir Simulation ◽  
History Matching ◽  
Control Volume ◽  
Base Case ◽  
Case Scenario ◽  
Injection Wells ◽  
Base Case Scenario ◽  
Development Scenarios ◽  
Production Wells ◽  
Grid Construction

<p>Reservoir simulation is an area of reservoir engineering in which computer models are used to predict the flow of fluids through porous media. Reservoir simulation process starts with several steps; data preparation, model and grid construction, initialization, history matching and prediction. Initialization process is done for matching OOIP or total initial hydrocarbon which fill reservoir with hydrocarbon control volume with volumetric method.</p><p>To aim the best encouraging optimum data, these development scenarios of TR Field Layer X will be predicted for 30 years (from 2014 until January 2044). Development scenarios in this study consist of 4 scenarios : Scenario 1 (Base Case), Scenario 2 (Base Case + Reopening non-active wells), Scenario 3 (scenario 2 + infill production wells), Scenario 4 (Scenario 2 + 5 spot pattern of infill injection wells).</p>

scholarly journals Increasing Efficiency of Field Water Re-Injection during Water-Flooding in Mature Hydrocarbon Reservoirs: A Case Study from the Sava Depression, Northern Croatia

2020 ◽  
Vol 12 (3) ◽  
pp. 786 ◽  
Author(s):  
Tomislav Malvić ◽  
Josip Ivšinović ◽  
Josipa Velić ◽  
Jasenka Sremac ◽  
Uroš Barudžija
Keyword(s):  
Water Injection ◽  
Inverse Distance Weighting ◽  
Hydrocarbon Reservoirs ◽  
Water Flooding ◽  
Injection Wells ◽  
Weighting Method ◽  
Hydrocarbon Production ◽  
Recovery Method ◽  
Distance Weighting ◽  
Inverse Distance

The authors analyse the process of water re-injection in the hydrocarbon reservoirs/fields in the Upper Miocene sandstone reservoirs, located in the western part of the Sava Depression (Croatia). Namely, this is the “A” field with “L” reservoir that currently produces hydrocarbons using a secondary recovery method, i.e., water injection (in fact, re-injection of the field waters). Three regional reservoir variables were analysed: Porosity, permeability and injected water volumes. The quantity of data was small for porosity reservoir “L” and included 25 points; for permeability and injected volumes of water, 10 points each were measured. This study defined selection of mapping algorithms among methods designed for small datasets (fewer than 20 points). Namely, those are inverse distance weighting and nearest and natural neighbourhood. Results were tested using cross-validation and isoline shape recognition, and the inverse distance weighting method is described as the most appropriate approach for mapping permeability and injected volumes in reservoir “L”. Obtained maps made possible the application of the modified geological probability calculation as a tool for prediction of success for future injection (with probability of 0.56). Consequently, it was possible to plan future injection more efficiently, with smaller injected volumes and higher hydrocarbon recovery. Prevention of useless injection, decreasing number of injection wells, saving energy and funds invested in such processes lead to lower environmental impact during the hydrocarbon production.

The Coupling Model of Wellbore Conduit Flow, Throttled Flow and Formation Seepage in Water Injection Wells

2012 ◽  
Vol 594-597 ◽  
pp. 2486-2489
Author(s):  
Bao Jun Liu ◽  
Hai Xia Shi ◽  
Yun Sheng Cai
Keyword(s):  
Flow Rate ◽  
Water Injection ◽  
Coupling Model ◽  
Water Flooding ◽  
Finite Radius ◽  
Injection Wells ◽  
Conduit Flow ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Low Efficiency

Separate layer water flooding is adopted in most oilfields in China and the injection flow rate is controlled by the diameter of water nozzle of each layer. In order to ensure the effect of water injection, applicable water nozzles need to be adjusted to meet the requirements of injection flow rate. The adjustment is commonly realized according to experience, which leads to long adjustment time and low efficiency. To solve this problem, the coupling model of wellbore conduit flow, throttled flow and formation seepage was established based on theoretical analysis, which could provide theoretical basis for water nozzles adjustment. In the model, the Bernoulli Equation was adopted to analyze wellbore conduit flow; indoor experiments were done to research throttled flow; the research object of the seepage was finite radius well in homogeneous infinite formation.

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.

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.

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