scholarly journals Correlation for Predicting Water Breakthrough Time in Thin Oil Rim Reservoirs in the Niger Delta

2018 ◽  
Vol 6 (3) ◽  
Author(s):  
Anietie Okon ◽  
Dulu Appah ◽  
Julius Akpabio
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Coefficient Of Determination ◽  
Reservoir Model ◽  
Breakthrough Time ◽  
Well Completion ◽  
Water Breakthrough ◽  
Oil Rim

In the Niger Delta, available correlations to predict water breakthrough time in thin oil rim reservoirs are based on generic reservoir models and/or experimental design approach. This approach had not considered the heterogeneity of the reservoir. Thus, the prediction of these available correlations for thin oil rim reservoirs in the Niger Delta is in doubt, considering the sensitive nature of developing thin oil rim reservoirs. Then, a correlation for water breakthrough time (tbt) was developed based on integrated reservoir model of thin oil rim reservoir in the Niger Delta. The obtained result indicated that the developed correlation predicted 1652.72 days compared to the actual Oilfield breakthrough time of 1653 days (about 4.53 years). Also, sensitivity study showed that the developed correlation and the integrated reservoir model predictions of oil production rate (qo), fractional well penetration (hp/h) and height above perforation-oil column (hap/h) on the water breakthrough time (tbt) were close and resulted in coefficient of determination (R2) of 0.9697, 0.8597 and 0.9553, respectively. Furthermore, the results depicted that water coning breakthrough time (tbt) depends directly on oil production rate (q) and well completion parameters: fractional well penetration (hp/h) and height above perforation (hap). Hence, to delay early water breakthrough in thin oil rim reservoirs, these completion parameters are consideration in vertical wells to achieve optimum oil recovery. Also, the developed correlation can be used as a quick and robust tool to predict water breakthrough time of thin oil rim reservoirs in the Niger Delta.

A Depletion Strategy for an Active Bottom-Water Drive Reservoir Using Analytical and Numerical Models—Field Case Study

2009 ◽  
Vol 131 (10) ◽  
Author(s):  
Ibrahim Sami Nashawi ◽  
Ealian H. Al-Anzi ◽  
Yousef S. Hashem
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Bottom Water ◽  
Numerical Models ◽  
Water Production ◽  
Breakthrough Time ◽  
Well Completion ◽  
Water Breakthrough ◽  
Water Coning ◽  
Single Well

Water coning is one of the most serious problems encountered in active bottom-water drive reservoir. It increases the cost of production operations, reduces the efficiency of the depletion mechanism, and decreases the overall oil recovery. Therefore, preventive measures to curtail water coning damaging effects should be well delineated at the early stages of reservoir depletion. Production rate, mobility ratio, well completion design, and reservoir anisotropy are few of the major parameters influencing and promoting water coning. The objective of this paper is to develop a depletion strategy for an active bottom-water drive reservoir that would improve oil recovery, reduce water production due to coning, delay water breakthrough time, and pre-identify wells that are candidates to excessive water production. The proposed depletion strategy does not only take into consideration the reservoir conditions, but also the currently available surface production facilities and future development plan. Analytical methods are first used to obtain preliminary estimates of critical production rate and water breakthrough time, then comprehensive numerical investigation of the relevant parameters affecting water coning behavior is conducted using a single well 3D radial reservoir simulation model.

scholarly journals Integrated-reservoir-model-based critical oil rate correlation for vertical wells in thin oil rim reservoirs in the Niger Delta

2018 ◽  
Vol 7 (3) ◽  
pp. 1757
Author(s):  
Anietie Ndarake Okon ◽  
Dulu Appah
Keyword(s):  
Niger Delta ◽  
Sensitivity Study ◽  
Coefficient Of Determination ◽  
Limited Attention ◽  
Optimization Approach ◽  
Reservoir Model ◽  
Vertical Wells ◽  
Chi Square ◽  
Water Coning ◽  
Oil Rim

Thin oil rim reservoirs are mostly characterized by development and production challenges; one of which is early water coning tendency. In the Niger Delta, most developed critical oil rate correlations to avert coning focused on conventional bottom-water drive reservoirs, while thin oil rim reservoirs received limited attention. Available correlations to estimate critical oil rate of thin oil rim reservoirs in Niger Delta are based on generic reservoir models, which does not consider the reservoir heterogeneity. Hence, it leaves these available correlations’ predictions in doubt, considering the sensitive nature of developing thin oil rim reservoirs. Thus, a correlation for critical oil rate (qc) based on integrated reservoir model in the Niger Delta was develop for thin oil rim reservoirs using multivariable numerical optimization approach. The obtained result indicated that the developed correlation predicted 226.05 bbl/day compared to the actual Oilfield critical oil rate of 226.11 bbl/day. Furthermore, sensitivity study indicated that the developed correlation and the integrated reservoir model predictions of fractional well penetration (hp/h) and height below perforation - oil column (hbp/h) on critical oil rate (qc) were close and resulted in coefficient of determination (R2) of 0.9266 and 0.9525, Chi square (X2) of 0.539 and 0.655, and RMSE of 4.336 and 4.357. Additionally, the results depict that critical oil rate depends indirectly on fractional well penetration and directly on height above perforation for vertical wells. Therefore, to delay water-coning tendency in thin oil rim reservoirs these completion parameters are consideration in vertical wells to establish optimum critical oil rate during hydrocarbons production. Also, the developed correlation can be used as a quick tool to estimate critical oil rate of thin oil rim reservoirs in the Niger Delta.  

Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

2021 ◽  
Author(s):  
Tinuola Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Core Samples ◽  
Recovery Potential ◽  
Secondary Formation ◽  
Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

scholarly journals Comparison Between Homogenous and Heterogeneous Reservoirs: A Parametric Study of Water Coning Phenomena

2021 ◽  
Vol 5 (1) ◽  
pp. 119-131
Author(s):  
Frzan F. Ali ◽  
Maha R. Hamoudi ◽  
Akram H. Abdul Wahab
Keyword(s):  
Production Rate ◽  
Oil Production ◽  
Water Production ◽  
Effective Parameters ◽  
Radial Cross Section ◽  
Heterogeneous Reservoirs ◽  
Water Breakthrough ◽  
Water Coning ◽  
Water Cut ◽  
Reservoir Simulator

Water coning is the biggest production problem mechanism in Middle East oil fields, especially in the Kurdistan Region of Iraq. When water production starts to increase, the costs of operations increase. Water production from the coning phenomena results in a reduction in recovery factor from the reservoir. Understanding the key factors impacting this problem can lead to the implementation of efficient methods to prevent and mitigate water coning. The rate of success of any method relies mainly on the ability to identify the mechanism causing the water coning. This is because several reservoir parameters can affect water coning in both homogenous and heterogeneous reservoirs. The objective of this research is to identify the parameters contributing to water coning in both homogenous and heterogeneous reservoirs. A simulation model was created to demonstrate water coning in a single- vertical well in a radial cross-section model in a commercial reservoir simulator. The sensitivity analysis was conducted on a variety of properties separately for both homogenous and heterogeneous reservoirs. The results were categorized by time to water breakthrough, oil production rate and water oil ratio. The results of the simulation work led to a number of conclusions. Firstly, production rate, perforation interval thickness and perforation depth are the most effective parameters on water coning. Secondly, time of water breakthrough is not an adequate indicator on the economic performance of the well, as the water cut is also important. Thirdly, natural fractures have significant contribution on water coning, which leads to less oil production at the end of production time when compared to a conventional reservoir with similar properties.

A Cost Effective, Fit-for-Purpose Single Well Producer-Injector Completion Strategy for Improved Recovery of Oil: Case Study in Niger Delta

2016 ◽  
Author(s):  
Pranav Dubey ◽  
Adrian Okpere ◽  
Gideon Sanni ◽  
Ifeanyi Onyeukwu
Keyword(s):  
Data Acquisition ◽  
Oil Recovery ◽  
Niger Delta ◽  
Water Saturation ◽  
Optimized Design ◽  
Production Forecast ◽  
Safety Control ◽  
Well Completion ◽  
Single Well ◽  
Fit For Purpose

ABSTRACT An optimized completion design that addresses gaps in the existing single well Producer-Injector (P-I) concept is presented in this paper. Field development scenarios based on the optimized P-I concept and conventional waterflood were implemented in full-field 3D simulation models. Detailed review of the existing single P-I well concept revealed gaps in the completion design with regards to feasibility of data acquisition, ease of well intervention and well safety/control. The existing design utilizes a Single-String-Single (SSS) design with through-tubing water injection and oil production through annulus, whilst the optimized design is a Two-String-Dual (TSD) incorporating the flexibility of independent injection/production, zonal isolation for interventions & data acquisition and additional safety completion jewelries. A fit-for-purpose reservoir candidate was selected by assessing it's suitability to waterflooding. The reservoir belongs to the paralic sequence of the Agbada Formation of the Niger Delta basin – a sequence of interbedded sandstones and shales. The reservoir is an elongated anticline bounded by W-E oriented faults and exhibiting channelized shoreface sediments. Porosity and permeability ranges are 17-31% and 200mD-2200mD respectively. Shale baffles strongly reduces the influence of the aquifer hence the simulation model is an oil reservoir with weak aquifer completed by the P-I well producing oil and injecting into the aquifer in tandem. Performance of the single P-I well strategy was benchmarked against conventional waterflood patterns to effectively capture the recovery efficiency and production forecast for each scenario. Results from the five-parameter experimental design based on the P-I strategy, indicate Ultimate Oil Recovery is most impacted by horizontal permeability; injection rate, flow barrier transmissibility and vertical permeability with the least influence. Dynamic 3D water saturation maps show the waterflood front propagating principally in the horizontal direction from the injector, providing important reservoir boundary pressure support and minimizing the chance for injected water short-circuiting at the sandface. Ultimate Oil Recovery of 5spot/line drive patterns and the P-I strategy were similar, 54% and 52% respectively. Well completion costs and forecasts were fed into simple economics spreadsheet to test which technique provides the most value. Open book economics results showed the P-I concept provides better value (NPV 23.0 and VIR 0.67) than 5 spot and line drive patterns (NPV-17 and VIR-0.14).

scholarly journals An Improved Mathematical Model for Accurate Prediction of the Heavy Oil Production Rate during the SAGD Process

Processes ◽  
2020 ◽  
Vol 8 (2) ◽  
pp. 235
Author(s):  
Aria Rahimbakhsh ◽  
Morteza Sabeti ◽  
Farshid Torabi
Keyword(s):  
Production Rate ◽  
Penetration Depth ◽  
Oil Recovery ◽  
Current Model ◽  
Oil Production ◽  
Exponential Model ◽  
Analytical Models ◽  
Test Facility ◽  
Drainage Rate ◽  
Heat Penetration

Steam-assisted gravity drainage (SAGD) is one of the most successful thermal enhanced oil recovery (EOR) methods for cold viscose oils. Several analytical and semi-analytical models have been theorized, yet the process needs more studies to be conducted to improve quick production rate predictions. Following the exponential geometry theory developed for finding the oil production rate, an upgraded predictive model is presented in this study. Unlike the exponential model, the current model divides the steam-oil interface into several segments, and then the heat and mass balances are applied to each of the segments. By manipulating the basic equations, the required formulas for estimating the oil drainage rate, location of interface, heat penetration depth of steam ahead of the interface, and the steam required for the operation are obtained theoretically. The output of the proposed theory, afterwards, is validated with experimental data, and then finalized with data from the real SAGD process in phase B of the underground test facility (UTF) project. According to the results, the model with a suitable heat penetration depth correlation can produce fairly accurate outputs, so the idea of using this model in field operations is convincing.

scholarly journals The effect of chemically enhanced oil recovery on thin oil rim reservoirs

2021 ◽  
Vol 11 (3) ◽  
pp. 1461-1474
Author(s):  
O. A. Olabode ◽  
V. O. Ogbebor ◽  
E. O. Onyeka ◽  
B. C. Felix
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Surfactant Concentration ◽  
Base Case ◽  
Production Studies ◽  
Water Alternating Gas ◽  
Water Coning ◽  
Oil Rim

AbstractOil rim reservoirs are characterised with a small thickness relative to their overlying gas caps and underlying aquifers and the development these reservoirs are planned very carefully in order to avoid gas and water coning and maximise oil production. Studies have shown low oil recoveries from water and gas injection, and while foam and water alternating gas injections resulted in positive recoveries, it is viewed that an option of an application of chemical enhanced oil recovery option would be preferable. This paper focuses on the application of chemical enhanced oil recovery to improve production from an oil rim reservoir in Niger Delta. Using Eclipse black oil simulator, the effects of surfactant concentration and injection time and surfactant alternating gas are studied on overall oil recovery. Surfactant injections at start and middle of production resulted in a 3.7 MMstb and 3.6 MMstb at surfactant concentration of 1% vol, respectively. This amounted to a 6.6% and 6.5% increment over the base case of no injection. A case study of surfactant alternating gas at the middle of production gave an oil recovery estimate of 10.7%.

scholarly journals NANO-SURFACTANT HUFF AND PUFF OPTIMATIZATION IN MARGINAL X FIELD USING COMMERCIAL SIMULATOR

2019 ◽  
Vol 42 (2) ◽  
pp. 51-57
Author(s):  
Ariel Paramastya ◽  
Steven Chandra ◽  
Wijoyo Niti Daton ◽  
Sudjati Rachmat
Keyword(s):  
Interfacial Tension ◽  
Production Rate ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Oil Production ◽  
Full Scale ◽  
Economic Aspect ◽  
Economic Optimization ◽  
Single Well

Economic optimization of an oil and gas project is an obligation that has to be done to increase overall profi t, whether the fi eld is still economically feas ible or the fi eld has surpassed its economic limit. In this case, a marginal fi eld waschosen for the study. In this marginal fi eld EOR methods have been used to boost the production rate. However, a full scale EOR method might not be profi table due to the amount of resources that is required to do it. Alternatively, Huff and Puff method is an EOR technique that is reasonable in the scope of single well. The Huff and Puff method is an EOR method where a single well serves as both a producer and an injector. The technique of Huff and Puff: (1) The well isinjected with designed injection fl uid, (2) the well is shut to let the fl uid to soak in the reservoir for some time, and (3) the well is opened and reservoir fl uids are allowed to be produced. The injection fl uid (in this case, nano surfactant) is hypothesized to reduce interfacial tension between the oil and rock, thus improving the oil recovery. In this study, the application of Huff and Puff method using Nanoparticles (NPs) as the injected fl uid, as a method of improving oil recovery is presented in a case study of a fi eld in South Sumatra. The study resulted that said method yields an optimum Incremental Oil Production (IOP) in which the economic aspect gain more profi t, and therefore it is considered feasible to be applied in the fi eld.

Seawater Breakthrough Monitoring and Reservoir-Model Improvement Using Natural Boron

2021 ◽  
Author(s):  
Yanqing Wang ◽  
Zhe Liu ◽  
Xiang Li ◽  
Shiqian Xu ◽  
Jun Lu
Keyword(s):  
Production Rate ◽  
History Matching ◽  
Produced Water ◽  
Clay Content ◽  
Ion Concentration ◽  
Geochemical Data ◽  
Reservoir Model ◽  
Concentration Data ◽  
Water Breakthrough ◽  
Reservoir Simulator

Abstract Natural geochemical data, which refer to the natural ion concentration in produced water, contain important reservoir information, but is seldomly exploited. Some ions were used as conservative tracers to obtain better knowledge of reservoir. However, using only conservative ions can limit the application of geochemical data as most ions are nonconservative and can either interact with formation rock or react with other ions. Besides, mistakenly using nonconservative ion as being conservative may cause unexpected results. In order to further explore the nonconservative natural geochemical information, the interaction between ion and rock matrix is integrated into the reservoir simulator to describe the nonconservative ion transport in porous media. Boron, which is a promising nonconservative ion, is used to demonstrate the application of nonconservative ion. Based on the new model, the boron concentration data together with water production rate and oil production rate are assimilated through ensemble smoother multiple data assimilation (ES-MDA) algorithm to improve the reservoir model. Results indicate that including nonconservative ion data in the history matching process not only yield additional improvement in permeability field, but also can predict the distribution of clay content, which can promote the accuracy of using boron data to determine injection water breakthrough percentage. However, mistakenly regarding nonconservative ion being conservative in the history matching workflow can deteriorate the accuracy of reservoir model.

Sign in / Sign up

Export Citation Format

Share Document