Identification and Impacts of Dual Strings Completion Leak in History Matching of Highly Faulted and Multi Layered Clastic Oil Reservoirs

2021 ◽  
Author(s):  
Nis Ilyani Mohmad ◽  
Danu Ismadi ◽  
Nor Hajjar Salleh ◽  
Amirul Nur Romle ◽  
Syarifah Puteh Syed Abd Rahim ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
History Matching ◽  
Production Performance ◽  
Model Parameters ◽  
Reservoir Model ◽  
Reservoir Performance ◽  
Tool Evaluation ◽  
Logging Tool

Abstract History matching is one of the paramount steps in reservoir model validation to describe, analyze and mimic the overall behavior of reservoir performance. Performing history matching on highly faulted and multi layered reservoirs is always challenging, especially when the wells are completed with multiple zones either with single selective or dual strings. The history matching complexity is also compounded with uncertainties in production allocation, well history and downhole equipment integrity overtime. It is a common practice for deterministic history matching in reservoir numerical simulation to modify the both static and dynamic model parameters within the subsurface uncertainty window. However, for multi layered reservoirs completed with dual strings, another parameter that is most often get overlooked is the completion string’s leaking phenomenon that tremendously impacting the history matching. The objective of this paper is to introduce dual strings leaking diagnostics methodology from various disciplines’ angles. We demonstrate these dual strings leaking phenomenon impact on history matching. This paper covers dual strings leak diagnostic methodology which includes production logging tool evaluation, well’s production performance and recovery factor analysis. Possible factors that gives rise to the string’s leaks including material corrosion from high CO2 and sand production will also be discussed. We will demonstrate on how the leak phenomenon could be mimicked in the reservoir numerical model. Possible risks on future infill well identification if the leaks phenomenon is not incorporated will be also discussed. The dual strings leaks diagnosis and application in numerical simulation is illustrated on a case study of Field "D", a multilayered sandstone reservoir in Malaysia of almost 3 decades of production. This proven leak identification and reservoir model history matching methodology has been replicated for all the fault blocks across the field. It potentially unlocks more than 100 MMSTB of additional oil recovery by drilling more oil producers and water injectors in future drilling campaigns.

Gravity Drainage System: Investigation and Field Development Using Geological Modelling and Reservoir Simulation

2021 ◽  
Author(s):  
Obinna Somadina Ezeaneche ◽  
Robinson Osita Madu ◽  
Ishioma Bridget Oshilike ◽  
Orrelo Jerry Athoja ◽  
Mike Obi Onyekonwu
Keyword(s):  
Reservoir Simulation ◽  
Structural Control ◽  
History Matching ◽  
Drainage System ◽  
Production Performance ◽  
Gravity Drainage ◽  
Base Case ◽  
Proper Understanding ◽  
Field Development ◽  
Reservoir Performance

Abstract Proper understanding of reservoir producing mechanism forms a backbone for optimal fluid recovery in any reservoir. Such an understanding is usually fostered by a detailed petrophysical evaluation, structural interpretation, geological description and modelling as well as production performance assessment prior to history matching and reservoir simulation. In this study, gravity drainage mechanism was identified as the primary force for production in reservoir X located in Niger Delta province and this required proper model calibration using variation of vertical anisotropic ratio based on identified facies as against a single value method which does not capture heterogeneity properly. Using structural maps generated from interpretation of seismic data, and other petrophysical parameters from available well logs and core data such as porosity, permeability and facies description based on environment of deposition, a geological model capturing the structural dips, facies distribution and well locations was built. Dynamic modeling was conducted on the base case model and also on the low and high case conceptual models to capture different structural dips of the reservoir. The result from history matching of the base case model reveals that variation of vertical anisotropic ratio (i.e. kv/kh) based on identified facies across the system is more effective in capturing heterogeneity than using a deterministic value that is more popular. In addition, gas segregated fastest in the high case model with the steepest dip compared to the base and low case models. An improved dynamic model saturation match was achieved in line with the geological description and the observed reservoir performance. Quick wins scenarios were identified and this led to an additional reserve yield of over 1MMSTB. Therefore, structural control, facies type, reservoir thickness and nature of oil volatility are key forces driving the gravity drainage mechanism.

scholarly journals Breccia interlayer effects on steam-assisted gravity drainage performance: experimental and numerical study

2021 ◽  
Author(s):  
Qichen Zhang ◽  
Xiaodong Kang ◽  
Huiqing Liu ◽  
Xiaohu Dong ◽  
Jian Wang
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Oil Sands ◽  
Numerical Study ◽  
Middle Part ◽  
Experimental Results ◽  
Production Performance ◽  
Peak Oil ◽  
Steam Chamber ◽  
The Impact

AbstractCurrently, the reservoir heterogeneity is a serious challenge for developing oil sands with SAGD method. Nexen’s Long Lake SAGD project reported that breccia interlayer was widely distributed in lower and middle part of reservoir, impeding the steam chamber expansion and heated oil drainage. In this paper, two physical experiments were conducted to study the impact of breccia interlayer on development of steam chamber and production performance. Then, a laboratory scale numerical simulation model was established and a history match was conducted based on the 3D experimental results. Finally, the sensitivity analysis of thickness and permeability of breccia layer was performed. The influence mechanism of breccia layer on SAGD performance was analyzed by comparing the temperature profile of steam chamber and production dynamics. The experimental results indicate that the existence of breccia interlayer causes a thinner steam chamber profile and longer time to reach the peak oil rate. And, the ultimate oil recovery reduced 15.8% due to much oil stuck in breccia interlayer areas. The numerical simulation results show that a lower permeability in breccia layer area has a serious adverse impact on oil recovery if the thickness of breccia layer is larger, whereas the effect of permeability on SAGD performance is limited when the breccia layer is thinner. Besides, a thicker breccia layer can increase the time required to reach the peak oil rate, but has a little impact on the ultimate oil recovery.

scholarly journals History Matching and Production Prediction of Steam Drive Reservoir Based on Data-Space Inversion Method

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
RuXiang Gong ◽  
JingSong Li ◽  
ZiJun Huang ◽  
Fei Wang ◽  
Hao Yang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
History Matching ◽  
Production Optimization ◽  
Production Performance ◽  
Inversion Method ◽  
Data Space ◽  
Steam Flooding ◽  
Space Inversion ◽  
Production Prediction

Recently, a data-space inversion (DSI) method has been proposed and successfully applied for the history matching and production optimization for conventional waterflooding reservoir. Under Bayesian framework, DSI can directly and effectively obtain posterior flow predictions without inverting any geological parameters of reservoir model. In this paper, we integrate the numerical simulation model with DSI method for rapid history matching and production prediction for steam flooding reservoir. Based on the finite volume method, a numerical simulation model is established and it is used to provide production data samples for DSI by the simulation of ensemble geological models. DSI-based production prediction model is then established and get trained by the historical data through the random maximum likelihood principle. The posterior production estimation can be obtained fast by training the DSI-based model with history data, but without any posterior geological parameters. The proposed method is applied for history matching and estimating production performance prediction in some numerical examples and a field case, and the results prove its effectiveness and reliability.

scholarly journals Reservoir Model and Production Strategy of Mishrif Reservoir-Nasryia Oil Field Southern Iraq

2020 ◽  
Vol 10 (3) ◽  
pp. 54-85
Author(s):  
Hamzah Amer Abdulameer ◽  
Dr. Sameera Hamd-Allah
Keyword(s):  
Oil Recovery ◽  
Carbonate Rock ◽  
History Matching ◽  
Water Saturation ◽  
Oil Field ◽  
Neutron Density ◽  
Reservoir Model ◽  
Water Contact ◽  
Medium Permeability ◽  
Production Strategy

Nasryia oil field is located about 38 Km to the north-west of Nasryia city. The field was discovered in 1975 after doing seismic by Iraqi national oil company. Mishrif formation is a carbonate rock (Limestone and Dolomite) and its thickness reach to 170m. The main reservoir is the lower Mishrif (MB) layer which has medium permeability (3.5-100) md and good porosity (10-25) %. Form well logging interpretation, it has been confirmed the rock type of Mishrif formation as carbonate rock. A ten meter shale layer is separating the MA from MB layer. Environmental corrections had been applied on well logs to use the corrected one in the analysis. The combination of Neutron-Density porosity has been chosen for interpretation as it is close to core porosity. Archie equation had been used to calculate water saturation using corrected porosity from shale effect and Archie parameters which are determined using Picket plot. Using core analysis with log data lead to establish equations to estimate permeability and porosity for non-cored wells. Water saturation form Archie was used to determine the oil-water contact which is very important in oil in place calculation. PVT software was used to choose the best fit PVT correlation that describes reservoir PVT properties which will be used in reservoir and well modeling. Numerical software was used to generate reservoir model using all geological and petrophysical properties. Using production data to do history matching and determine the aquifer affect as weak water drive. Reservoir model calculate 6.9 MMMSTB of oil as initial oil in place, this value is very close to that measured by Chevron study on same reservoir which was 7.1 MMMSTB. [1] Field production strategy had been applied to predict the reservoir behavior and production rate for 34 years. The development strategy used water injection to support reservoir pressure and to improve oil recovery. The result shows that the reservoir has the ability to produce oil at apparently stable rate equal to 85 Kbbl/d, also the recovery factor is about 14%.

A Novel Workflow for Optimizing Well Placement Under Geomechanical Constraints: A Case Study

2020 ◽  
Vol 143 (3) ◽  
Author(s):  
Cheng An ◽  
Peng Zhang ◽  
Amanveer Wesley ◽  
Gaetan Bardy ◽  
Kevin Hall ◽  
...  
Keyword(s):  
Stress Field ◽  
Three Dimensional ◽  
Production Performance ◽  
Natural Fracture ◽  
Petrophysical Properties ◽  
Reservoir Model ◽  
Differential Stress ◽  
Well Placement ◽  
Flow Simulations

Abstract A novel workflow to optimize well placement using geomechanical constraints is introduced to maximize production performance, reduce excessive simulation runs, and minimize drilling constraints by considering the local stress field and the petrophysical properties in a given reservoir. A case study is presented for optimization of horizontal well placement in the Monterey Formation of Miocene Age in California. First, a three-dimensional reservoir model of formation pressure, in situ stresses, petrophysical and rock properties were built from available petrophysical and well log data. Second, numerical modeling using material point method (MPM) was applied to generate the differential stress field, taking into consideration a three-dimensional natural fracture network in the reservoir model. Third, an optimization algorithm which incorporates petrophysical properties, natural fracture distribution, differential stresses, and mechanical stability was used to identify the best candidate locations for well placement. Finally, flow simulations were conducted to segregate each candidate location where both natural and hydraulic fractures were considered. Statistical methods identify optimal well positions in areas with low differential stress, high porosity, and high permeability. Several candidate locations for well placement were selected and flow simulations were conducted. A comparison of the production performance between the best candidates and other randomly selected well configurations indicates that the workflow can effectively recognize scenarios of optimum well placement. The proposed workflow provides practical insight on well placement optimization by reducing the number of required reservoir simulation runs and maximizing the hydrocarbon recovery.

scholarly journals Oil recovery for fractured-vuggy carbonate reservoirs by cyclic water huff and puff: performance analysis and prediction

2019 ◽  
Vol 9 (1) ◽  
Author(s):  
Daigang Wang ◽  
Jingjing Sun
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
High Efficiency ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Production Performance ◽  
Quantitative Prediction ◽  
Attractive Alternative ◽  
Marquardt Algorithm ◽  
The Impact

Abstract Cyclic water huff and puff (CWHP) has proven to be an attractive alternative to improve oil production performance after depletion-drive recovery in fractured-vuggy carbonate reservoirs. However, due to the impact of strong heterogeneity, multiple types of fractured-vuggy medium, poor connectivity, complex flow behaviors and oil-water relationship, CWHP is merely suitable for specific types of natural fractured-vuggy medium, usually causing a great difference in actual oil-yielding effect. It remains a great challenge for accurate evaluation of CWHP adaptability and quantitative prediction of production performance in fractured-vuggy carbonate reservoir, which severely restricts the application of CWHP. For this study, we firstly enable the newly developed fuzzy grey relational analysis to quantify the adaptability of CWHP. With production history of several targeted producers, the accuracy of the proposed method is validated. Based on the traditional percolation theory and waterflood mechanisms in various types of fractured-vuggy medium, a quantitative prediction model for cyclic water cut fwp and increased recovery factor ΔR is presented. The CWHP production performance is discussed by using the Levenberg-Marquardt algorithm for history matching. With a better understanding of the fwp ~ ΔR curve characteristics in different types of fractured-vuggy medium, proper strategies or measures for potential-tapping remaining oil are provided. This methodology can also offer a good basis for engineers and geologists to develop other similar reservoirs with high efficiency.

Parameters Estimation for Chemical Flooding Modeling Using Ensemble-Based Method

2021 ◽  
Author(s):  
Xindan Wang ◽  
Yin Zhang ◽  
Abhijit Dandekar ◽  
Yudou Wang
Keyword(s):  
Simulation Model ◽  
Oil Recovery ◽  
History Matching ◽  
Simulation Models ◽  
Parameters Estimation ◽  
Model Parameters ◽  
Chemical Flooding ◽  
Multiple Model ◽  
Assisted History Matching ◽  
Matching Techniques

Abstract Chemical flooding has been widely used to enhance oil recovery after conventional waterflooding. However, it is always a challenge to model chemical flooding accurately since many of the model parameters of the chemical flooding cannot be measured accurately in the lab and even some parameters cannot be obtained from the lab. Recently, the ensemble-based assisted history matching techniques have been proven to be efficient and effective in simultaneously estimating multiple model parameters. Therefore, this study validates the effectiveness of the ensemble-based method in estimating model parameters for chemical flooding simulation, and the half-iteration EnKF (HIEnKF) method has been employed to conduct the assisted history matching. In this work, five surfactantpolymer (SP) coreflooding experiments have been first conducted, and the corresponding core scale simulation models have been built to simulate the coreflooding experiments. Then the HIEnKF method has been applied to calibrate the core scale simulation models by assimilating the observed data including cumulative oil production and pressure drop from the corresponding coreflooding experiments. The HIEnKF method has been successively applied to simultaneously estimate multiple model parameters, including porosity and permeability fields, relative permeabilities, polymer viscosity curve, polymer adsorption curve, surfactant interfacial tension (IFT) curve and miscibility function curve, for the SP flooding simulation model. There exists a good agreement between the updated simulation results and observation data, indicating that the updated model parameters are appropriate to characterize the properties of the corresponding porous media and the fluid flow properties in it. At the same time, the effectiveness of the ensemble-based assisted history matching method in chemical enhanced oil recovery (EOR) simulation has been validated. Based on the validated simulation model, numerical simulation tests have been conducted to investigate the influence of injection schemes and operating parameters of SP flooding on the ultimate oil recovery performance. It has been found that the polymer concentration, surfactant concentration and slug size of SP flooding have a significant impact on oil recovery, and these parameters need to be optimized to achieve the maximum economic benefit.

scholarly journals Modelling of continuous surfactant flooding application for marginal oilfields: a case study of Bentiu reservoir

2021 ◽  
Author(s):  
Azza Hashim Abbas ◽  
Hani Hago Elhag ◽  
Wan Rosli Wan Sulaiman ◽  
Afeez Gbadamosi ◽  
Peyman Pourafshary ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Oil Production ◽  
Simulation Modelling ◽  
Sensitivity Study ◽  
Surfactant Flooding ◽  
Oil Saturation ◽  
Proxy Model ◽  
Proven Method

AbstractEnhanced oil recovery (EOR) is a proven method to increase oil production from the brown fields. One of the efficient EOR methods is injecting surfactants to release the trapped oil. However, few unconsolidated behaviours were observed in both field and laboratory practice. In this study, a new framework was adapted to evaluate the continuous surfactant flooding (CSF) in Bentiu reservoir. The study aims to quantify the expected range of the oil production, recovery factor and residual oil saturation (Sor). The motivation came from the oil demand in Sudan and the insufficient cores. The framework adopted in the study includes numerical simulation modelling and proxy modelling. Thirty-six cores obtained from the field were revised and grouped into five main groups. The interfacial tension (IFT) data were obtained experimentally. The CSF sensitivity study was developed by combining different experimental design sets to generate the proxy model. The CSF numerical simulation results showed around 30% additional oil recovery compared to waterflooding and approximately oil production between (20–30) cm3. The generated proxy model extrapolated the results with concerning lower ranges of the input and showed an average P50 of oil production and recovery of 74% and 17 cm3, respectively. Overall, the performance of CSF remained beneficial in vast range of input. Moreover, the generated proxy model gave an insight on the complexity of the interrelationship between the input factors and the observants with a qualitative prospective factors. Yet, the results confirmed the applicability of CSF in core scale with an insight for field scale application.

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