Integrated Subsurface Study for Gas-Oil Communicating Reservoirs: From Structural Synthesis to Optimum Co-FDP

2021 ◽  
Author(s):  
Mohamad Yousef Alklih ◽  
Andi Ahmad Salahuddin ◽  
Karem Alejandra Khan ◽  
Nidhal Mohamed Aljneibi ◽  
Coriolan Rat ◽  
...  
Keyword(s):  
Decision Making ◽  
Reservoir Characterization ◽  
Development Planning ◽  
Co2 Injection ◽  
Oil Reservoir ◽  
Discounted Cash Flow ◽  
Field Development ◽  
Development Scenarios ◽  
Pressure Depletion ◽  
Field Management

Abstract This paper presents an integrated subsurface study that focuses on delivering field development planning of two reservoirs via comprehensive reservoir characterization workflows. The upper gas reservoir and lower oil reservoir are in communication across a major fault in the crest area of the structure. Gas from the upper reservoir, which is not under development, is being produced along with some oil producers from the oil reservoir as per acquired surveillance data. Pressure depletion is observed in observer wells of the upper reservoir, which substantiate both reservoirs communication. The oil reservoir is on production since 1994, under miscible hydrocarbon water alternating gas injection (HCWAG) and carbon dioxide (CO2) injection. The currently implemented development plan has been facing several complexities and challenges including, but not limited to, maintaining miscibility conditions, sustainability of production and injection in view of reservoirs communication, reservoir modeling challenges, suitability of monitoring strategy, associated operating costs and expansion of field development in newly appraised areas. In this study, an assessment of multiple alternative field development scenarios was conducted; with an aim to tackle field management and reservoir challenges. It commenced by a comprehensive synthesis of seismic, petrophysical (including extensive core characterizations), geological, production and reservoir engineering data to ensure data adequacy and effectiveness for development planning. The process was followed by evaluation of the historical reservoir management, HCWAG and CO2 injection practices using advanced analytics to identify areas for improvement and accelerate decision making process. The identified areas of improvement were incorporated into a dynamic model via diverse set of field management logics to screen wide range of scenarios. In the final step, the optimal scenarios were selected, in line of having strong economic indicators, honoring operational constraints, corporate business plan and strategic objectives. The comprehensive and flexible field management logic was set up to target different challenges and was used to extensively screen hundreds of different field development scenarios varying several parameters. Examples of such parameters are WAG ratio, injection pressures for both water/gas and CO2, cycle duration, well placement, reservoir production and injection guidelines, different co-development production schemes coupled with static and dynamic uncertainty properties against incremental oil production and discounted cash flow. The simulation results were analyzed using standardized approach where a number of key indicators was cross-referenced to produce optimal field development scenarios with regards to co-development effect of both reservoirs, miscibility conditions, balanced pressure depletion, harmonized sweep as well as robust discounted cash flow. Strong management support, multi-disciplinary data integration, agility of decision making and revisions in a controlled timeframe are considered as the key pillars for success of this study. The adopted workflow covers subsurface modeling aspects from A-Z and following reservoir characterization and modeling best practices. The methodology applied in this study uses an integrated subsurface structured approach to tackle reservoirs challenges and co-development, generate alternative development options leveraging on data analytics techniques and advanced field management strategies.

A geomechanical approach for sanding risk assessment applied to three field cases for completion optimisation

2010 ◽  
Vol 50 (1) ◽  
pp. 623 ◽  
Author(s):  
Khalil Rahman ◽  
Abbas Khaksar ◽  
Toby Kayes
Keyword(s):  
Decision Making ◽  
Petroleum Industry ◽  
Cost Effective ◽  
Development Planning ◽  
Control Measures ◽  
Sand Production ◽  
Field Development ◽  
Well Completion ◽  
Sand Control ◽  
Production Prediction

Mitigation of sand production is increasingly becoming an important and challenging issue in the petroleum industry. This is because the increasing demand for oil and gas resources is forcing the industry to expand its production operations in more challenging unconsolidated reservoir rocks and depleted sandstones with more complex well completion architecture. A sand production prediction study is now often an integral part of an overall field development planning study to see if and when sand production will be an issue over the life of the field. The appropriate type of sand control measures and a cost-effective sand management strategy are adopted for the field depending on timing and the severity of predicted sand production. This paper presents a geomechanical modelling approach that integrates production or flow tests history with information from drilling data, well logs and rock mechanics tests. The approach has been applied to three fields in the Australasia region, all with different geological settings. The studies resulted in recommendations for three different well completion and sand control approaches. This highlights that there is no unique solution for sand production problems, and that a robust geomechanical model is capable of finding a field-specific solution considering in-situ stresses, rock strength, well trajectory, reservoir depletion, drawdown and perforation strategy. The approach results in cost-effective decision making for appropriate well/perforation trajectory, completion type (e.g. cased hole, openhole or liner completion), drawdown control or delayed sand control installation. This type of timely decision making often turns what may be perceived as an economically marginal field development scenario into a profitable project. This paper presents three case studies to provide well engineers with guidelines to understanding the principles and overall workflow involved in sand production prediction and minimisation of sand production risk by optimising completion type.

Subsurface-to-Economics Closing the Loop on Uncertainty Analysis

2021 ◽  
Author(s):  
Galvin Shergill ◽  
Adrian Anton ◽  
Kwangwon Park
Keyword(s):  
Measurement Errors ◽  
Oil And Gas ◽  
Uncertainty Modeling ◽  
Weather Forecast ◽  
Oil And Gas Industry ◽  
Development Planning ◽  
Gas Field ◽  
Field Development ◽  
Development Scenarios ◽  
Uncertainty Model

Abstract We are all aware that our future is uncertain. Although some aspects can be predicted with more certainty and others with less, essentially everything is uncertain. Uncertainty exists because of lack of data, lack of resources, and lack of understanding. We cannot measure everything, so there are always unknowns. Even measurements include measurement errors. Also, we do not always have enough resources to analyze the data obtained. In addition, we do not have a full understanding of how the world, or the universe, works (Park 2011). Every day we find ourselves in situations where we must make many decisions, big or small. We tend to make the decisions based on a prediction, despite knowing that it is uncertain. For instance, imagine how many decisions are made by people every day based on the probability of it raining tomorrow (i.e., based on the weather forecast). To have a good basis for making a decision, it is of critical importance to correctly model the uncertainty in the forecast. In the oil and gas industry, uncertainties are large and complex. Oil and gas fields have been developed and operated despite tremendous uncertainty in a variety of areas, including undiscovered media and unpredictable fluid in the subsurface, wells, unexpected facility and equipment costs, and economic, political, international, environmental, and many other risks. Another important aspect of uncertainty modeling is the feasibility of verifying the uncertainty model with the actual results. For example, in the weather forecast it was announced that the probability of raining the next day was 20%. And the next day it rained. Do we say the forecast was wrong? Can we say the forecast was right? In order to make sure the uncertainty model is correct; we should strictly verify all the assumptions and follow the mathematically, statistically, proven-to-be-correct methodology to model the uncertainty (Caers et al. 2010; Caers 2011). In this paper, we show an effective, rigorous method of modeling uncertainty in the expected performance of potential field development scenarios in the oil and gas field development planning given uncertainties in various domains from subsurface to economics. The application of this method is enabled by using technology as described in a later section.

World's First Extension Pack with 7-in. Enhanced Single-Trip Multizone System: Success Case and Learning Points on the Installation and Treatment Design

2021 ◽  
Author(s):  
Sunanda Magna Bela ◽  
Abdil Adzeem B Ahmad Mahdzan ◽  
Noor Hidayah A Rashid ◽  
Zairi A Kadir ◽  
Azfar Israa Abu Bakar ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Development Planning ◽  
Development Project ◽  
Lessons Learned ◽  
High Rate ◽  
Individual Treatment ◽  
Flow Area ◽  
Field Development ◽  
Well Completion ◽  
Gravel Pack

Abstract Gravel packing in a multilayer reservoir during an infill development project requires treating each zone individually, one after the other, based on reservoir characterization. This paper discusses the installation of an enhanced 7-in. multizone system to achieve both technical and operational efficiency, and the lessons learned that enabled placement of an optimized high-rate water pack (HRWP) in the two lower zones and an extension pack in the uppermost zone. This new approach helps make multizone cased-hole gravel-pack (CHGP) completions a more technically viable and cost-effective solution. Conventional CHGPs are limited to either stack-pack completions, which can incur high cost because of the considerable rig time required for multizone operations, or alternate-path single-trip multizone completions that treat all the target zones simultaneously, with one pumping operation. However, this method does not allow for individual treatment to suit reservoir characterization. The enhanced 7-in. multizone system can significantly reduce well completion costs and pinpoint the gravel placement technique for each zone, without pump-rate limitations caused by excessive friction in the long interval system, and without any fiuid-loss issues after installation because of the modular sliding side-door (SSD) screen design feature. A sump packer run on wireline acts as a bottom isolation packer and as a depth reference for subsequent tubing-conveyed perforating (TCP) and wellbore cleanup (WBCU) operations. All three zones were covered by 12-gauge wire-wrapped modular screens furnished with blank pipe, packer extension, and straddled by two multizone isolation packers between the zones, with a retrievable sealbore gravel-pack packer at the top. The entire assembly was run in a single trip, therefore rig time optimization was achieved. The two lower zones were treated with HRWPs, while the top zone was treated with an extension pack. During circulation testing on the lowermost zone, high pumping pressure was recorded, and after thorough observation of both pumping parameters and tool configuration, it was determined that the reduced inner diameter (ID) in the shifter might have been a causal factor, thereby restricting the flow area. This was later addressed with the implementation of a perforated pup joint placed above the MKP shifting tool. The well was completed within the planned budget and time and successfully put on sand-free production, exceeding the field development planning (FDP) target. The enhanced 7-in. multizone system enabled the project team to beat the previous worldwide track record, which was an HRWP treatment only. As a result of proper fluid selection and rigorous laboratory testing, linear gel was used to transport 3 ppa of slurry at 10 bbl/min, resulting in a world-first extension pack with a 317-lbm/ft packing factor.

Quantitative 4D Seismic Assisted History Matching Using Ensemble-Based Methods on the Vilje Field

2020 ◽  
Author(s):  
Konrad Wojnar ◽  
Jon S?trom ◽  
Tore Felix Munck ◽  
Martha Stunell ◽  
Stig Sviland-Østre ◽  
...  
Keyword(s):  
Decision Making ◽  
Seismic Data ◽  
History Matching ◽  
Reservoir Characterization ◽  
Reservoir Management ◽  
History Match ◽  
Field Development ◽  
Qualitative And Quantitative ◽  
Reservoir Models ◽  
4D Seismic

Abstract The aim of the study was to create an ensemble of equiprobable models that could be used for improving the reservoir management of the Vilje field. Qualitative and quantitative workflows were developed to systematically and efficiently screen, analyze and history match an ensemble of reservoir simulation models to production and 4D seismic data. The goal of developing the workflows is to increase the utilization of data from 4D seismic surveys for reservoir characterization. The qualitative and quantitative workflows are presented, describing their benefits and challenges. The data conditioning produced a set of history matched reservoir models which could be used in the field development decision making process. The proposed workflows allowed for identification of outlying prior and posterior models based on key features where observed data was not covered by the synthetic 4D seismic realizations. As a result, suggestions for a more robust parameterization of the ensemble were made to improve data coverage. The existing history matching workflow efficiently integrated with the quantitative 4D seismic history matching workflow allowing for the conditioning of the reservoir models to production and 4D data. Thus, the predictability of the models was improved. This paper proposes a systematic and efficient workflow using ensemble-based methods to simultaneously screen, analyze and history match production and 4D seismic data. The proposed workflow improves the usability of 4D seismic data for reservoir characterization, and in turn, for the reservoir management and the decision-making processes.

Bringing Flexibility and Automation to Well Testing Operations Through Wireless Telemetry - Case Study

2021 ◽  
Author(s):  
Elias Temer ◽  
Deiveindran Subramaniam ◽  
Yermek Kaipov ◽  
Carlos Merino ◽  
Vladimirovich Latvin ◽  
...  
Keyword(s):  
Real Time ◽  
Reservoir Characterization ◽  
Time Window ◽  
Weather Conditions ◽  
Development Planning ◽  
Testing Time ◽  
Well Testing ◽  
Well Test ◽  
Real Time Control ◽  
Field Development

Abstract Dynamic reservoir data are a key driver for operators to meet the forecasted production investments of their fields. However, many challenges during well testing, such as reduced exploration and capex budgets, complex geologic structures, and inclement weather conditions that reduce the well testing time window can prevent them from gathering critical reservoir characterization data needed to make more informed field development planning decisions. To overcome these challenges, a live, downhole reservoir testing platform enabled the most representative reservoir information in real time and connected more zones of interest in a single run for appraisal wells in the Sea of Okhotsk, Russia. This paper describes the test requirements, the prejob planning, and automated execution of wirelessly enabled operations that led to the successful completion of the well test campaign in very hostile conditions, a remote area, and restricted period. The use of a telemetry system to well testing in seven zones enabled real-time control of critical downhole equipment and acquired data at surface, which in turn was transmitted to the operator's office in town in real time. Various operation examples will be discussed to demonstrate how automated data acquisition and downhole operations control has been used to optimize operations by both the service company and the operator.

scholarly journals Integrated Field Development Plans of Akkas Gas Field

2020 ◽  
Vol 10 (3) ◽  
pp. 102-122
Author(s):  
Dr. Jalal A. Al-Sudani ◽  
Eng. Adnan N. Sajet ◽  
Eng. Jalal Ahmed ◽  
Eng. Mohamed Enad ◽  
Dr. Abdul-Hussain H. Al-Shibly ◽  
...  
Keyword(s):  
Net Present Value ◽  
Planning Process ◽  
Development Planning ◽  
Gas Production ◽  
Recovery Factor ◽  
Western Desert ◽  
Discounted Cash Flow ◽  
Gas Field ◽  
Field Development ◽  
Development Plans

Akkas gas field is the biggest natural gas field in Iraq that is located in the western desert area. The field contains around (9 BSCF) of approved gas reserve from the conventional rock source. This paper presents field development planning process combined with economic analysis comprises, the number of wells that yields in maximum net present value (NPV), the recovery factor and raw gas production rates for the total number of suggested wells that have been estimated, as well as the cumulative gas produced with time. The development plans were elaborated concerning different types of well geometries and operational constraints. Full comparison analysis for all presented plans regarding NPV, recovery factor, discounted cash flow versus production time, forecasted production rate, as well as forecasted cumulative production with time have been presented. Sensitivity analysis has been made to determine well and reservoir controlling parameters that leads for best operating field development plans. The study shows the effectiveness of horizontal well type compared with vertical wells; as well as, the effect of reservoir permeability on field development plans, the results show that the field could be operated at target plateau rates of (250, 500 and 750 MMSCF/D). It also shows the superior effect of stimulation processes in increasing the NPV and field recovery factor using less number of wells

scholarly journals Assessing Potential Thermo-Mechanical Impacts on Caprock Due to CO2 Injection—A Case Study from Northern Lights CCS

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 5054
Author(s):  
Nicholas Thompson ◽  
Jamie Stuart Andrews ◽  
Tore Ingvald Bjørnarå
Keyword(s):  
Effective Stress ◽  
Carbon Capture ◽  
Storage System ◽  
Carbon Capture And Storage ◽  
Development Planning ◽  
Co2 Injection ◽  
Field Development ◽  
Stress Changes ◽  
Pressure Changes ◽  
And Storage

Due to significant temperature differences between the injected medium and in situ formation, injection of CO2 (as with water or other cold fluids) at depth induces thermal changes that must be accounted for a complete understanding of the mechanical integrity of the injection/storage system. Based on evaluations for the Northern Lights Carbon Capture and Storage (CCS) project, we focus on thermal effects induced on the caprock via conduction from cooling in the storage sands below. We investigate, using both analytical and numerical approaches, how undrained effects within the low permeability caprock can lead to volumetric contraction differences between the rock framework and the pore fluid which induce both stress and pore pressure changes that must be properly quantified. We show that such undrained effects, while inducing a more complicated response in the stress changes in the caprock, do not necessarily lead to unfavourable tensile conditions, and may, in fact, lead to increases in effective stress. These observations build confidence in the integrity of the caprock/seal system. We also show, through conservative assumptions, that pressure communication between the caprock and storage sands may lead to a localised negative effective stress condition, challenging stability of the base caprock, which will be mitigated for in field development planning.

Minimise Risks Through a Comprehensive Validation of the Existing Production Operation and Planning Strategy for the Largest Oilfield in Poland

2021 ◽  
Author(s):  
Siew Hiang Khor ◽  
Jacek Dudek ◽  
Piotr Wojcik ◽  
Krzysztof Pietrzyk ◽  
Daniel Podsobinski ◽  
...  
Keyword(s):  
Network Models ◽  
Development Plan ◽  
Production Operation ◽  
Operation Strategy ◽  
Safe Operation ◽  
Field Development ◽  
Operating Strategy ◽  
Development Scenarios ◽  
Process Plant ◽  
Field Management

Abstract Integrated field management is a key initiative recognised by many operators that helps delivering the promise of digital to meet their business strategic objectives of increased hydrocarbon production, reduced exploration and appraisal costs, and sustained development and operation costs. This paper presents how an integrated asset model has been developed for the largest oilfield in Poland to enable a comprehensive validation of its current development plan and operating strategy to ensure safe operation; assessment of other feasible development scenarios to fully realise its potential and paving the path to digital oilfield. A proven integrated asset modeling approach has been adopted to bring a complex reservoir, multiple interdependent wells, pipelines networks, process models together into one single platform. The integrated modeling platform included both gas and water reinjection network models to provide a pore to process closed loop solution. Development of this integrated reservoir-wells-pipelines-network-process facility-water and gas reinjection network models focused to provide all the vital valuable inputs to better field management, fast and accurate decision-making, optimal safe operation in meeting the set seasonal sales contract. Assessments of production operation strategy and field development scenarios were conducted at full field level from reservoir to process plant, accounting wells, pipelines, process handling capacities, the complete system constraints and back pressure effects of all involved components. The availability of fully integrated asset model with pore to process solution enables engineers to better understand the current well performance and production potentials; to ensure a safe and optimal process plant operation. The model helped to identify bottlenecks imposed by the existing pipelines network and process facility; it also enabled the asset team to confirm the existing development plan was not optimal. Other feasible planning scenarios which could further enhance the overall asset productivity were identified, i.e. via determining location of infill wells and which unused idle producers to be converted to gas or water injectors. The study demonstrated a comprehensive validation of the existing development and operation strategy was achievable with the approach. The paper describes how the developed integrated asset model enables the asset team to validate the existing operating strategy and field development scenario of the studied onshore brownfield; to further enhance asset productivity and to achieve efficient field management by adjusting the operating condition in meeting the seasonal sales contract. The integrated asset model also helps to evaluate and to analyse forecasts of different development scenarios including infill drilling and adding new wells and other enhanced oil recovery (EOR) techniques to achieve an ultimate recovery and asset economics.

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