Integrated Dynamic Synthesis as Key Success to Sustain Oil Production in Mahakam: Case Water Flooding Project in Handil Field

2021 ◽  
Author(s):  
A. H. Surbakti
Keyword(s):  
Reservoir Simulation ◽  
Water Injection ◽  
Oil Production ◽  
Recovery Factor ◽  
Water Flooding ◽  
Sweet Spot ◽  
Main Zone ◽  
Spot Area ◽  
Dynamic Synthesis ◽  
Main Challenge

The Handil field is located in the Kutai Basin with an anticlinal structure consisting of a vertically stacked reservoirs deposited in a fluvial-deltaic environment. The field has been producing since 1974 under active aquifer drive followed by peripheral water injection which resulting in a high recovery factor of oil production. Cumulative oil production is more than 900 MMbbls and currently the field is still producing at 15000 bopd. The Handil Main zone is the main contributor that accounts for 60% of the Handil Field production and based on the results of new wells drilling, there is still potential of the remaining oil accumulations. Therefore, an integrated subsurface study is needed to further increase recovery in the Handil Main zone. This paper will discuss the process used to locate unswept oil in the high water cut reservoir to extend the water flood project. Waterflooding became an important part of the Handil’s development strategy to maximize oil recovery and to maintain oil reservoir pressure, as more and more fields are matured as part of their production life cycle. The main challenge is to identify area of unsweep oil that are affected by water injection activity. Understanding the reservoir behavior of the water injection sweep characteristic can significantly improve the understanding of the distribution of unswept oil in the reservoir. A robust integrated methodology was developed to identify unswept oil area by integrating Static- dynamic synthesis, 3D static model, production history, reservoir connectivity, recent well logs data and reservoir simulation. Multiple QC of oil sweet spot are done by comparing the sweet spot area of dynamic synthesis with reservoir simulation. Detailed well correlation were performed to identify the optimum water injector placement to improve the recovery factor. The results of the integrated dynamic synthesis are used to identify the sweet spot area and the optimum well injector location that will be used for the water flooding development project to be executed in 2022. The results of the study will sustain Mahakam production in the future.

Optimising Oil Field Net Present Value with Produced Water Salinities and Tracers

2021 ◽  
Author(s):  
Babalola Daramola
Keyword(s):  
Reservoir Simulation ◽  
Produced Water ◽  
Water Injection ◽  
Oil Production ◽  
Oil Field ◽  
Water Flooding ◽  
Water Salinity ◽  
History Match ◽  
Infill Drilling ◽  
Salinity Data

Abstract This paper presents case studies of how produced water salinity data was used to transform the performance of two oil producing fields in Nigeria. Produced water salinity data was used to improve Field B’s reservoir simulation history match, generate infill drilling targets, and reinstate Field C’s oil production. A reservoir simulation study was unable to history match the water cut in 3 production wells in Field B. Water salinity data enabled the asset team to estimate the arrival time of injected sea water at each production well in oil field B. This improved the reservoir simulation history match, increased model confidence, and validated the simulation model for the placement of infill drilling targets. The asset team also gained additional insight on the existing water flood performance, transformed the water flooding strategy, and added 9.6 MMSTB oil reserves. The asset team at Field C was unable to recover oil production from a well after it died suddenly. The team evaluated water salinity data, which suggested scale build up in the well, and completed a bottom-hole camera survey to prove the diagnosis. This justified a scale clean-out workover, and added 5000 barrels per day of oil production. A case study of how injection tracer data was used to characterise a water injection short circuit in Field D is also presented. Methods of using produced water salinity and injection tracer data to manage base production and add significant value to petroleum fields are presented. Produced water salinity and injection tracer data also simplify water injection connectivity evaluations, and can be used to justify test pipeline and test separator installation for data acquisition.

Improving Water Injectivity Through Lateral Radial Drilling into the Reservoir

2021 ◽  
Author(s):  
Effiong Essien ◽  
Uchenna Onyejiaka ◽  
Stanley Onwukwe ◽  
Nnaemeka Uwaezuoke
Keyword(s):  
Oil Recovery ◽  
Damage Zone ◽  
Water Injection ◽  
Progressive Increase ◽  
Recovery Factor ◽  
Water Flooding ◽  
Increase With Increase ◽  
Drilling Technology ◽  
Water Cut ◽  
Radial Drilling

Abstract Poor formation permeability and near well bore damage may limit water injectivity into the reservoir in a water injection project. This paper seeks to evaluate the effect of radial drilling technique on water injectivity and oil recovery in water flooding operation. Radial drilling technology utilizes hydraulic energy to create lateral perpendicular small holes through the casing into the reservoir. The holes may extend to 100 m (330 ft) into the reservoir to access fresh formations beyond the near wellbore, and damage zone. A black oil simulator (Eclipse 100) was used to modeling a lateral radial drill from the borehole into the reservoir, and that of a conventional perforation of the wellbore respectively. A simulation study was carried out using various presumed radial drill configurations in determining injectivity index, displacement efficiencies, recovery factor and water cut of the process. The determined results were further compared with that of the conventional perforation process case respectively. The results show a significant improvement in water injectivity in radial drill case with the increasing length and number of radials as compared to the conventional wellbore perforation case. The determined Recovery factor shows a progressive increase with increase in the numbers of radials drilled, irrespective of the radial length. However, it was observed that, the more the number and length of the radials drilled in to the reservoir, the higher the water cut from producer wells. Radial Drilling Technology, therefore, has a promising potential to improving water injectivity into the reservoir and thereby optimizing oil recovery in a water flooding operation.

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.

Rigorous Performance Evaluation of Stochastic Optimization for Water Injection Strategies

2021 ◽  
Author(s):  
Nader BuKhamseen ◽  
Ali Saffar ◽  
Marko Maucec
Keyword(s):  
Simulation Model ◽  
Reservoir Simulation ◽  
Water Injection ◽  
Oil Production ◽  
Optimization Techniques ◽  
Evolutionary Strategies ◽  
Stochastic Methods ◽  
Water Production ◽  
Reservoir Simulation Model ◽  
Injection Strategies

Abstract This paper presents an approach to optimize field water injection strategies using stochastic methods under uncertainty. For many fields, voidage replacement was the dictating factor of setting injection strategies. Determining the optimum injection-production ratio (IPR) requires extensive experience taking into consideration all the operational facility constraints. We present the outcome of a study, in which several optimization techniques were used to find the optimum field IPR values and then elaborate on the techniques? strengths and weaknesses. The synthetic reservoir simulation model, with millions of grid blocks and significant numbers of producers and injectors, was divided into seven IPR regions based on a streamline study. Each region was assigned an IPR value with an associated uncertainty interval. An ensemble of fifty probabilistic scenarios was generated by experimental design, using Latin Hypercube sampling of IPR values within tolerance limits. Scenarios were used as the main sampling domain to evaluate a family of optimization engines: population-based methods of artificial intelligence (AI), such as Genetic algorithms and Evolutionary strategies, Bayesian inference using sequential or Markov chain Monte Carlo, and proxy-based optimization. The optimizers were evaluated based on the recommended IPR values that meet the objective of minimizing the water cut by maximizing oil production and minimizing water production. The speed of convergence of the optimization process was also a subject of evaluation. To ensure unbiased sampling of IPR values and to prevent oversampling of boundary extremes, a uniform triangular distribution was designed. The results of the study show a clear improvement of the objective function, compared to the initial sampled cases. As a direct search method, the Evolutionary strategies with covariance matrix adaptation (ES-CMA) yielded the optimum IPR value per region. While examining the effect of applying these IPR values in the reservoir simulation model, a significant reduction of water production from the initial cases without an impact on the oil production was observed. Compared to ESCMA, other optimization methods have dem

Process Design of Cyclic Water Flooding by Real-Time Monitoring

2018 ◽  
Vol 140 (11) ◽  
Author(s):  
Kobra Pourabdollah
Keyword(s):  
Real Time ◽  
Production Rate ◽  
Process Design ◽  
Water Injection ◽  
Oil Production ◽  
Oil Field ◽  
Water Flooding ◽  
Injection System ◽  
Real Time Monitoring ◽  
Naturally Fractured

The gradual decline in the oil production rate of water flooded reservoirs leads to decrease in the profit of water flooding system. Although cyclic water injection (CWI) was introduced to reduce the descending trend of oil production in water flooded reservoirs, it must be optimized based upon the process parameters. The objective of this study is to develop all process design criteria based upon the real-time monitoring of CWI process in a naturally fractured reservoir having five producing wells and five injector wells completed in an Arab carbonated formation containing light crude oil (API = 42 deg). For this aim, a small pilot oil field was selected with water injection facilities and naturally producing oil wells and all data were collected from the field tests. During a five years' field test, the primary observations at the onset of shutdown periods of the water injection system revealed a repeatable significant enhancement in oil production rate by a factor of plus 5% leading us to assess the application of CWI. This paper represents the significant parameters of pressure and productivity affected during CWI in naturally fractured carbonate reservoirs based upon a dual porosity generalized compositional model. The results hopefully introduce other oil producer companies to the potential of using CWI to increase oil production in conventional water injection systems. The results also outline situations where such applications would be desirable.

A Method to Determine the Optimal Water Injection Intensity Based on Oil Production Rate and Water Cut

2012 ◽  
Vol 594-597 ◽  
pp. 2442-2445 ◽  
Author(s):  
Ji Cheng Zhang ◽  
Ying Jia ◽  
Xiao Na Cui
Keyword(s):  
Production Rate ◽  
Water Injection ◽  
Oil Production ◽  
Water Flooding ◽  
Water Intensity ◽  
Water Cut ◽  
Relationship Of ◽  
The Relationship ◽  
Oilfield Development ◽  
Zone Water

Water injection is one of the important ways to maintain reservoir pressure and improving the oilfield development effect. And separate zone water injection is the main technology in water flooding oilfield. The optimal water intensity which has been allocated plays an important role in all kinds of reservoir. This paper proposed a method to optimize the water injection intensity based on oil production rate and water cut. Conceptual model was constructed on the basis of real reservoir. By numerical simulation, a chart board was derived which describes the relationship of water injection intensity versus oil production rate and water cut. Using this chart, we can determine the optimal water injection intensity on different oil production rate and water cut.

scholarly journals The Key Parameter Effect Analysis Of Polymer Flooding On Oil Recovery Using Reservoir Simulation

2019 ◽  
Vol 4 (1) ◽  
pp. 49
Author(s):  
Tomi Erfando ◽  
Novia Rita ◽  
Romal Ramadhan
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Polymer Concentration ◽  
Polymer Flooding ◽  
Recovery Factor ◽  
Water Flooding ◽  
Base Case ◽  
Driving Mechanism ◽  
Geological Condition ◽  
Recovery Method

As time goes by, there will be decreasing of production rates of a field along with decreasing pressure. This led to the necessity for further efforts to increase oil production. Therefore, pressure support is required to improve the recovery factor. Supportable pressure that can be used can be either water flooding and polymer flooding. This study aims to compare recovery factor to scenarios carried out, such as polymer flooding with different concentrations modeled in the same reservoir model to see the most favorable scenario. The method used in this research is reservoir simulation method with Computer Modeling Group (CMG) STARS simulator. The study was carried out by observing at the pressure, injection rate, and polymer concentration on increasing field recovery factor. This study used cartesian grid with the assumption of homogeneous reservoir, there are no faults or other geological condition in the reservoir, and driving mechanism is only solution gas drive. This reservoir, oil type is light oil with API gravity 40.3˚API and layer of conglomerate rock. The simulation result performed with various scenarios provides a good result. Where the conditions case base case field recovery factor of 6.7%, and after water flooding produced 25.5% of oil, whereas with tertiary recovery method is polymer flooding was carried out with four concentrations of 640 ppm, 1,500 ppm, 3,000 ppm, and 4,000 ppm obtained optimum values at 4,000 ppm polymer concentration with recovery factor 28.9%, SOR reduction final value 0,5255, polymer adsorption of 818,700 ppm, reservoir final pressure 1,707 psi, and an increase in water viscosity to 0.94 cP.

An Efficient Workflow for Production Allocation During Water Flooding

2016 ◽  
Vol 139 (3) ◽  
Author(s):  
Vahid Azamipour ◽  
Mehdi Assareh ◽  
Mohammad Reza Dehghani ◽  
Georg M. Mittermeir
Keyword(s):  
Objective Function ◽  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Coarse Grid ◽  
Recovery Factor ◽  
Total Water ◽  
Production Schedule ◽  
Production Rates ◽  
Total Oil

This paper presents an efficient production optimization scheme for an oil reservoir undergoing water injection by optimizing the production rate for each well. In this approach, an adaptive version of simulated annealing (ASA) is used in two steps. The optimization variables updating in the first stage is associated with a coarse grid model. In the second step, the fine grid model is used to provide more details in final solution search. The proposed method is formulated as a constrained optimization problem defining a desired objective function and a set of existing field/facility constraints. The use of polytope in the ASA ensures the best solution in each iteration. The objective function is based on net present value (NPV). The initial oil production rates for each well come from capacity and property of each well. The coarse grid block model is generated based on average horizon permeability. The proposed optimization workflow was implemented for a field sector model. The results showed that the improved rates optimize the total oil production. The optimization of oil production rates and total water injection rate leads to increase in the total oil production from 315.616 MSm3 (our initial guess) to 440.184 MSm3, and the recovery factor is increased to 26.37%; however, the initial rates are much higher than the optimized rates. Beside this, the recovery factor of optimized production schedule with optimized total injection rate is 3.26% larger than the initial production schedule with optimized total water injection rate.

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

The Success Story of Secondary Recovery Using Peripheral Method Waterflooding in Carbonate Reservoir North East Air Serdang (NEASD) and Guruh (GRH) Field Pertamina Hulu Energi Ogan Komering

2020 ◽  
Author(s):  
J. Mulyono
Keyword(s):  
Water Injection ◽  
Tracer Tests ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Water Flooding ◽  
Injection System ◽  
Economic Evaluations ◽  
Success Story ◽  
North East ◽  
The Government

After completing the Geological Geophysical and Reservoir (GGR) model revision of North East Air Serdang (NEASD) and the Guruh (GRH) field, Pertamina Hulu Energi Ogan Komering (PHE OK) evaluated the water flooding performance that has been applied since 2006. This paper explains the success story of the water flooding application using the peripheral method in the carbonate reservoir NEASD and the GRH field in the Ogan Komering Block. Water flooding was successfully applied in the NEASD and Guruh fields. The carbonate reservoirs are well connected as evidenced by tracer tests conducted in 2006. The waterflood development was based on running the simulation water injection sensitivity cases, economic evaluations, and entailed converting the unproductive wells into injector wells and building an injection system surface facilities. The approved Plan of Further Development (POFD), covered field wide application of the waterflood and performance surveillance monitoring. The POFD of water flooding in NEASD and Guruh field was approved in 2006 by the government and fulfilled all of the commitments in 2018 with oil incremental production of 4.85 MMBO from a do nothing baseline recovery factor (RF) of 26.5% going up to 34.2% (post water flooding). Although this had fulfilled the programs and economic commitment, currently both of the fields still produce about 1500 bopd. After updating the Geological Geophysical and Reservoir (GGR) model in 2019, it is predicted that the total economic recovery factor (RF) of the development can reach 41,7% by the end of the PSC contract in 2038.

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