Field Applications of a Semianalytical Model of Multilateral Wells in Multilayer Reservoirs

2010 ◽  
Vol 13 (06) ◽  
pp. 861-872 ◽  
Author(s):  
Yan Pan ◽  
Medhat M. Kamal ◽  
Jitendra Kikani
Keyword(s):  
Constant Pressure ◽  
Lessons Learned ◽  
Oil Field ◽  
Production Performance ◽  
Well Performance ◽  
Unknown Parameters ◽  
Reservoir Properties ◽  
Multilayer Systems ◽  
Main Challenge ◽  
Transient Data

Summary Advanced drilling technology has been widely and successfully applied to construct multilateral wells in reservoirs. This paper presents several field applications of a generalized semianalytical segmented model accounting for multilateral-well systems in commingled layered reservoirs. Cases include a heavy-oil field, Al Rayyan oil field offshore Qatar, and Dos Cuadras field offshore California. The model can predict the production performance under either constant-rate or constant-pressure conditions of a well system with any number of arbitrarily oriented laterals of any length and nonuniform formation damage. The reservoir layers, with different porosities, anisotropic permeabilities, and drainage areas, are noncommunicating except through the wellbore. The solution is valid for large reservoirs and when no-flow or constant-pressure boundaries affect the pressure behavior. Results of applying this method in the field cases showed that the model enabled us to predict multilateral-well performance, to obtain information about reservoir connectivity, and to estimate well and reservoir properties in a multilayer system. Uncertainty caused by the large number of unknown parameters in such a complex system represents the main challenge in using this method. It is recommended to use other means together with pressure transient data to reduce the uncertainty. The presented model and the lessons learned from the field applications provide engineers with a tool enabling the use of transient data collected from multilateral wells in multilayer systems for reservoir characterization and performance forecast.

Production Performance Analysis of Volga-Ural Mature Waterflood with PRIME Diagnostic Metrics

2021 ◽  
Author(s):  
Artur Mihailovich Aslanyan ◽  
Bulat Galievich Ganiev ◽  
Azat Abuzarovich Lutfullin ◽  
Ildar Zufarovich Farkhutdinov ◽  
Marat Yurievich Garnyshev ◽  
...  
Keyword(s):  
Performance Analysis ◽  
Production Performance ◽  
Diagnostic Tools ◽  
Practical Case ◽  
Well Performance ◽  
Summary Table ◽  
Main Challenge ◽  
Production History ◽  
Infill Drilling ◽  
Production Trend

Abstract The paper presents a practical case of production performance analysis at one of the mature waterflood oil fields located at the Volga-Ural oil basin with a large number of wells. It is a big challenge to analyse such a large production history and requires a systematic approach. The main production complication is quite common for mature waterflood projects and includes non-uniform sweep, complicated by thief injection and thief water production. The main challenge is to locate the misperforming wells and address their complications. With the particular asset, the conventional single production analysis techniques (oil production trend, watercut trend, reservoir and bottom-hole pressure trend, productivity trend, conventional pressure build-up surveys and production logging) in the vast majority of cases were not capable of qualifying the well performance and assessing of remaining reserves status. The performance analysis of such an asset should be enhanced with new diagnostic tools and modern methods of data integration. The current study has made a choice in favor of using a PRIME analysis which is multi-parametric analytical workflow based on a set of conventional and non-conventional diagnostic metrics. The most effective diagnostics in this study have happened to be those are based on 3D dynamic micro-models, which are auto-generated from the reservoir data logs. PRIME also provided useful insights on well performance, formation properties and the current conditions of drained reserves which helped to select the candidates for infill drilling, pressure maintenance, workovers, production target adjustments and additional surveillance. The paper illustrates the entire PRIME workflow, starting from the top-level field data analysis, all the way to generating a summary table containing well diagnostics, justifications and recommendations.

Defining Heterogeneity and Compartmentalisation Predictions of Minor Reservoirs in Fluvial Environments: Geological and Dynamic Context

2021 ◽  
Author(s):  
Nur Azah Zulkifli ◽  
Lisa Claire Chisholm ◽  
Amy Mawarni M Yusoff ◽  
Nur Khairina Kosnon ◽  
Mohd Zubair Mohd Azkah ◽  
...  
Keyword(s):  
Seismic Analysis ◽  
Primary Objective ◽  
Lessons Learned ◽  
Reservoir Modeling ◽  
Well Performance ◽  
Reservoir Properties ◽  
Reservoir Prediction ◽  
Depositional Facies ◽  
Fundamental Study ◽  
Well Production

Abstract Reservoirs in MN Field comprise predominantly fluvial delta deposits. A number of reservoir modeling studies have been performed for major reservoirs, however, there are still challenges to be addressed. After 20 plus years of production, a project for minor reservoirs has been crafted based on the understanding and challenges of major reservoirs. The primary objective of this study was to improve the understanding of the uncertainties impacting the well performance and reservoir connectivity; and to find potential infill opportunities. A 2D conceptual modelling approach was used as a practical way to incorporate the static and dynamic data of logs, core, seismic and pressure data. Taking the lessons learned from the major reservoir performances, this study focused on the fluvial reservoir sedimentology to address and decrease the uncertainties through the different scales of heterogeneity. Consequently, depositional facies maps were developed with the integration of geophysical study and interpretation derived from seismic analysis. These integrated depositional facies maps were then further refined with the well production data and scenarios of multiple compartments from multiple iterations to fit into the conceptual models of this field. Refined paleo depositional maps for these minor reservoirs allowed for a better understanding on reservoir heterogeneities and further improved the geological understanding. This fundamental study can show us a more precise distribution and tendency of the sand and the scales of heterogeneity with different depositional facies. However, capturing and preserving the different levels of heterogeneities and compartmentalization is complex for some thin sand reservoirs which are below seismic resolution and have low correlation of reservoir properties-seismic response. Additionally, multiple compartments were inferred due to pressure difference and multiple contacts within a reservoir. This was further complicated by the uncertainty in log interpretation due to inadequacy of high confidence data (DST/fluid sampling), suppressed resistivity from shaly sands and below log resolution of thin beds. Despite of these issues and challenges, with integration of all the data available and rigorous team discussions; the minor reservoirs depo-facies, static and dynamic compartmentalization were finalized, leading to enhancement of reservoir prediction, communication and quality.

Expansion of Data Analytics for Optimizing Steamflood In Mukhaizna Heavy Oil Field

2021 ◽  
Author(s):  
Mohammed Al Asimi ◽  
Nasar Al Qasabi ◽  
Duc Le ◽  
Yuchen Zhang ◽  
Di Zhu ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Data Analytics ◽  
Oil Production ◽  
Steam Injection ◽  
Lessons Learned ◽  
Oil Field ◽  
Production Performance ◽  
Optimization Process ◽  
Successful Implementation ◽  
Full Field

Abstract After successful implementation of data analytics for steamflood optimization at the Mukhaizna heavy oil field in Oman late 2018, Occidental expanded the project to two additional areas with a total of 626 wells in 2019, followed by full field coverage of more than 3,200 wells in 2020. In 2019, two separate low-fidelity proxy models were built to model the two pilot areas. The models were updated with more features to account for additional reservoir phenomena and a larger scope. On the proxy engine side, speed and robustness were improved, resulting in reduced CPU processing time and lower cost. Because of advancements in software programing and the pilots’ encouraging production performance, full-field coverage was accelerated so the model could support the efforts in optimizing steam injection during the 2020 OPEC+ production cut, not only to comply with allotted quotas, but also to allocate the resources optimally, especially the costly steam. Good improvements have been observed in overall steamflood performance, the models’ capabilities, and the optimization workflow. The steam/oil ratio has been reduced through the increase in oil production in both expanded study areas while keeping the total steam injection volume constant. Overall field steam utilization was improved both during the 2020 OPEC+ production cuts and during the production ramp-up stage afterward. With the continuous improvement in supporting tools and scripts, most of the steam optimization process steps were automated, from preparing, checking, and formatting input data to analyzing, validating, and visualizing the model outputs. Another result of these improvements was the development of a user-friendly web application to manage the model workflow efficiently. This web app greatly improved the process of case submittals, including data preparation and QC, running models (history matching and forecasting), as well as visualization of the entire workflow. In terms of optimization workflow, these improvements resulted in less time spent by the field optimization engineer in updating, refreshing, and generating new model recommendations. It also helped reduce the time spent by the reservoir management team (RMT) to test and validate the new ideas before field implementation. This paper will describe the improvements in the proxy model and the overall optimization process, show the observed oil production increases, and discuss the challenges faced and the lessons learned.

THE ROLE OF RESERVOIR SIMULATION IN THE DEVELOPMENT OF THE CHALLIS AND CASSINI FIELDS

1990 ◽  
Vol 30 (1) ◽  
pp. 212
Author(s):  
I.G.D. Gorman
Keyword(s):  
Water Injection ◽  
Oil Field ◽  
Production Performance ◽  
Analytical Models ◽  
Production Test ◽  
Well Performance ◽  
Initial Development ◽  
Field Development ◽  
Production Wells ◽  
Interference Test

The Challis oil field development was approved in 1987 with marginal reserves (for an isolated offshore project) of 22 MMbbl. The initial development envisaged three subsea production wells connected via a riser to a floating production facility with one water injector also being required to maximise recovery. However, due to additional potential in the vicinity of the field, the production system was designed to accommodate up to 10 production/injection wells.Further appraisal in 1988/1989 doubled the reserves to 43 MMbbl and increased the number of initial production wells to seven from five reservoirs. The appraisal results also confirmed earlier concerns as to the structural complexity of the field. Analytical interpretations of the production tests performed on the wells could not be fully reconciled with the available well log, core and seismic data. Furthermore, the analytical models developed from these interpretations could not fully match the test results.Reservoir simulation was used to resolve, where possible, the discrepancies. Individual reservoir models were calibrated with the production test results and used to quantify the major uncertainties and their potential impact on production performance. The simulation results indicated that water injection may not be required. However, the degree of internal reservoir communication and the extent of the expected aquifer support were identified as the two principal unknowns.Production policy and monitoring procedures were structured to resolve these uncertainties as quickly as possible during the production start-up phase. Comparative forecasts of expected performance were developed for each reservoir with various levels of aquifer support. A surface controlled interference test was designed to investigate the extent of internal reservoir communication in the main reservoir.The success of the interference test and the results of the early well performance have confirmed the simulation predictions. Simulation modelling was successful in quantifying the range of expected pressure response (to production) for each reservoir and was able to quickly confirm the degree of pressure support present in each reservoir.

scholarly journals Evaluation of Waterflooding Effectiveness in the Tournaisian-Famennian Deposit of the Magovskoye Field

2020 ◽  
Vol 20 (3) ◽  
pp. 242-252
Author(s):  
Nadezhda A. Lyadova ◽  
◽  
Vladimir A. Demchenko ◽  
Keyword(s):  
Carbonate Reservoir ◽  
Production Performance ◽  
Positive Energy ◽  
Well Performance ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Current State ◽  
Natural Energy ◽  
Geological Conditions ◽  
Low Efficiency

Waterflooding effectiveness of the structurally complex carbonate reservoir in the Tournaisian-Famennian formation of the Magovskoye field is studied. This formation is characterised with hardened geological conditions, which affects the development efficiency. The work includes analysis of the history and current state of the formation development, production and injection well performance, the reservoir natural energy contents, the reservoir pressure performance across wells, formation geology and lithofacies structure. A correlation was established between the well performance and lithofacies heterogeneity of the formation. A combination of boundary and marginal flooding systems is arranged at the formation target, which shows low efficiency. The wells located in the edge reservoir areas exhibit low reservoir pressures; these areas feature low reservoir properties. Concurrently, there is a difference between the upper and lower parts of the section. The wells drilled into the lower part of the section show a positive water production performance and positive energy level, which is associated with the aquifer influence. The wells drilled into the upper part of the section show lower reservoir properties, higher compartmentalisation and no aquifer influence. The wells located in the areas with low reservoir pressures were reviewed, the reasons for the depleted content of energy were identified and research proposals were provided. Furthermore, we considered the well intervention operations performed at the formation in question and at formations of similar fields in the corresponding geological field conditions, and identified operations with the highest technological effects. As a result of the studies, well intervention operations were proposed, subject to the specific structure of the lithofacies zones and the nature of the relationship between production and injection wells. It will result in enhancing the waterflood system effectiveness and affecting the target development efficiency, in general.

Designing a Robust Surfactant Based SP Formulation in High Clay Containing Low Permeability Indonesian Field

2021 ◽  
Author(s):  
Andi Bachtiar ◽  
Octaviani Octaviani ◽  
Iqbal Fauzi ◽  
Sayak Roy ◽  
Roberto Company ◽  
...  
Keyword(s):  
Oil Recovery ◽  
High Throughput Screening ◽  
Lessons Learned ◽  
Oil Field ◽  
Reservoir Rock ◽  
Low Permeability ◽  
Screening Experiments ◽  
Main Challenge ◽  
Chemical Eor ◽  
Rock Characterization

Abstract Indonesian oil and gas reserves have been depleting since 2000 with no major addition of new oil reserves. Therefore, it is imperative to increase national oil production by optimizing the mature fields through the implementation of successful EOR technology. Out of this approach, a comprehensive study has been carried out on the targeted field by exploring the potential of surfactant-polymer (SP) flooding. This article describes the formulation design, optimization, and lessons learned leading up to a successful and robust chemical EOR formulation designing for a low permeability and high clay (>20% clay) containing Indonesian oil field. The detailed workflow consists of analysis of fluid and rock characterization, tailor-made SP formulation designing, optimization and coreflood validation as presented in previous papers (Bazin, 2010). A series of surfactant formulation were designed and screened synthetically through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools for ultra-low interfacial tension (IFT), solubility, compatibility with brine and polymer. Rock mineralogy has played an important role due to heterogeneity and very high (>20%) clay content. Surfactants retention through adsorption on reservoir rocks was the main constraint to achieve high performance and economical chemical EOR for the targeted field. Specific strategies by optimizing the surfactant formulation and by injecting adsorption inhibitor thus needed to be deployed to mitigate high surfactant retention. The detailed laboratory screening experiments conclude that the designed robust SP formulation is able to induce ultra-low IFT, excellent solubility and compatibility at the injection water salinity. The dynamic coreflood experiment using reservoir rock shows high incremental oil recovery (>60% ROIP) in short SP slug injection. As expected from the nature of rock, adsorption was the main challenge encountered during the course of this study, which resulted in a very promising oil recovery in economically realistic conditions.

Innovative Washpipe Free Circulating ICD Delivers Reduced Well Construction Costs

2021 ◽  
Author(s):  
Zhihua Wang ◽  
Daniel Newton ◽  
Aqib Qureshi ◽  
Yoshito Uchiyama ◽  
Georgina Corona ◽  
...  
Keyword(s):  
United Arab Emirates ◽  
Drilling Fluid ◽  
Aqueous Fluid ◽  
Control Device ◽  
Lessons Learned ◽  
Innovative Technology ◽  
Well Performance ◽  
Construction Costs ◽  
Inflow Control Device ◽  
Testing Field

Abstract This Extended Reach Drilling (ERD) field re-development of a giant offshore field in the United Arab Emirates (UAE) requires in most cases extremely long laterals to reach the defined reservoir targets. However, certain areas of the field show permeability and / or pressure variations along the horizontal laterals. This heterogeneity requires an inflow control device (ICD) lower completion liner to deliver the required well performance that will adequately produce and sweep the reservoir. The ICD lower completion along with the extremely long laterals means significant time is spent switching the well from reservoir drilling fluid (RDF) non-aqueous fluid (NAF) to an aqueous completion brine. To reduce the amount of rig time spent on the displacement portion of the completion phase, an innovative technology was developed to enable the ICDs to be run in hole in a closed position and enable circulating through the end of the liner. The technology uses a dissolvable material, which is installed in the ICD to temporarily plug it. The dissolvable material is inert to the RDF NAF while the ICDs are run into hole, and then dissolves in brine after the well is displaced from RDF NAF to completion brine, changing the ICDs from closed to an open position. The ability to circulate through the end of the liner, with the support of the plugged ICDs, when the lower completion is deployed and at total depth (TD), enables switching the well from RDF NAF drilling fluid to an aqueous completion brine without the associated rig time of the original displacement method. The technique eliminates the use of a dedicated inner displacement string and allows for the displacement to be performed with the liner running string, saving 4-5 days per well. An added bonus is that the unique design allowed for this feature to be retrofitted to existing standard ICDs providing improved inventory control. In this paper the authors will demonstrate the technology and system developed to perform this operation, as well as the qualification testing, field installations, and lessons learned that were required to take this solution from concept to successful performance improvement initiative.

Unlocking By-Passed Oil with Autonomous Inflow Control Devices Through an Integrated Approach

2021 ◽  
Author(s):  
Pawan Agrawal ◽  
Sharifa Yousif ◽  
Ahmed Shokry ◽  
Talha Saqib ◽  
Osama Keshtta ◽  
...  
Keyword(s):  
Continuous Production ◽  
Oil Production ◽  
Gas Production ◽  
Oil Field ◽  
Production Performance ◽  
Fluid Distribution ◽  
Flow Profile ◽  
Horizontal Drain ◽  
Control Devices

Abstract In a giant offshore UAE carbonate oil field, challenges related to advanced maturity, presence of a huge gas-cap and reservoir heterogeneities have impacted production performance. More than 30% of oil producers are closed due to gas front advance and this percentage is increasing with time. The viability of future developments is highly impacted by lower completion design and ways to limit gas breakthrough. Autonomous inflow-control devices (AICD's) are seen as a viable lower completion method to mitigate gas production while allowing oil production, but their effect on pressure drawdown must be carefully accounted for, in a context of particularly high export pressure. A first AICD completion was tested in 2020, after a careful selection amongst high-GOR wells and a diagnosis of underlying gas production mechanisms. The selected pilot is an open-hole horizontal drain closed due to high GOR. Its production profile was investigated through a baseline production log. Several AICD designs were simulated using a nodal analysis model to account for the export pressure. Reservoir simulation was used to evaluate the long-term performance of short-listed scenarios. The integrated process involved all disciplines, from geology, reservoir engineering, petrophysics, to petroleum and completion engineering. In the finally selected design, only the high-permeability heel part of the horizontal drain was covered by AICDs, whereas the rest was completed with pre-perforated liner intervals, separated with swell packers. It was considered that a balance between gas isolation and pressure draw-down reduction had to be found to ensure production viability for such pilot evaluation. Subsequent to the re-completion, the well could be produced at low GOR, and a second production log confirmed the effectiveness of AICDs in isolating free gas production, while enhancing healthy oil production from the deeper part of the drain. Continuous production monitoring, and other flow profile surveys, will complete the evaluation of AICD effectiveness and its adaptability to evolving pressure and fluid distribution within the reservoir. Several lessons will be learnt from this first AICD pilot, particularly related to the criticality of fully integrated subsurface understanding, evaluation, and completion design studies. The use of AICD technology appears promising for retrofit solutions in high-GOR inactive strings, prolonging well life and increasing reserves. Regarding newly drilled wells, dedicated efforts are underway to associate this technology with enhanced reservoir evaluation methods, allowing to directly design the lower completion based on diagnosed reservoir heterogeneities. Reduced export pressure and artificial lift will feature in future field development phases, and offer the flexibility to extend the use of AICD's. The current technology evaluation phases are however crucial in the definition of such technology deployments and the confirmation of their long-term viability.

Cement Conundrum: Valuable Lessons Learned for Sustaining Production

2021 ◽  
Author(s):  
Siti Najmi Farhan binti Zulkipli
Keyword(s):  
New Technology ◽  
Processing Parameters ◽  
Lessons Learned ◽  
Critical Element ◽  
Well Performance ◽  
Bond Quality ◽  
Quality Issue ◽  
Cement Integrity ◽  
Production Period ◽  
Cement Bond Quality

Abstract Addressing wellbore integrity through cement evaluation has been an evergreen topic which frequently catches major operators by surprise due to premature water or gas breakthrough causing low production attainability from the wells. Managing idle well strings arising from integrity issues is also a challenge throughout the production period. The remedial solutions to these issues do not come conveniently and require high cost during late life well intervention which often erodes the well economic limit. A critical element of wellbore barrier which is cement integrity evaluation is proposed to be uplifted and given a new perspective to define success criteria for producer wells to achieve certain reserves addition and production recovery. This paper will highlight integrated factors affecting cement bond quality, impact to well production, potential remedies for poor cement bond observed leveraging on the enhanced workflow and new technology and way forward to proactively prevent the unwanted circumstances in the first opportunity taken. A set of recommendations and prioritization criteria for future cement improvement will be also highlighted. Several case specific wells logged with variable cement bond evaluation tools are re-assessed and deep-dived to trace the root causes for unsatisfactory cement bond quality observed which include reservoir characteristics, understanding anomalies during drilling and cementing operation, identifying cement recipe used, log processing parameters applied and observing best practices during cementing operation to improve the quality. New and emerging cement evaluation technology inclusive of radioactive-based logging to meet specific well objectives will be also briefly discussed in terms of differences and technical deliverables. Looking at each spectrum, results show that there are several interdependent factors contributing to poor cement bond quality observed. Accurate understanding of formation behavior, designing fit-for-purpose cement recipe and adequate planning for cementing operation on well-by-well basis are among the top- notch approaches to be applied for an acceptable cement bond quality and placement. Statistics show that 27% to 64% of production attainability is achieved by wells with good cement quality within the first 3 months of production and this increases to 85% to 98% up until 7 months of production period, while only 12% production attainability achieved for those wells with adverse cement quality issue. In another well, water cut as high as 47% since the first day of production is observed which keeps increasing up to 40% thereafter. In a nutshell, cement evaluation exercise shall not be treated as vacuum, instead it requires an integrated foundation and close collaboration to materialize the desired outcomes. Arresting the issue with the right approach in the first place will be the enabler for optimum well performance and productivity to exceed the recovery target.

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