Localisation and Recovery Planning of the Remaining Hydrocarbon Reserves

2021 ◽  
Author(s):  
Artur Mihailovich Aslanyan ◽  
Arkadii Yurievich Popov ◽  
Ivan Aleksandrovich Zhdanov ◽  
Eugeny Sergeevich Pakhomov ◽  
Nikolay Petrovich Ibryaev ◽  
...  
Keyword(s):  
Dynamic Behavior ◽  
Complex Analysis ◽  
Full Range ◽  
Development Planning ◽  
Hydraulic Fractures ◽  
Fine Grid ◽  
Field Development ◽  
Digital Twin ◽  
Digital Asset ◽  
The Cross

Abstract The paper presents the results of a study project of 60+ well block of the large (> 1,000 wells) mature (30 year old) oilfield in Western Siberia with objective to localise and characterize residual recoverable reserves and propose the optimal economic scenario for further depletion. Low permeability, heterogeneous reserve structure along the cross-section, numerous induced hydraulic fractures in producing wells and numerous spontaneous fractures in injecting wells with dynamic behavior, aggravated by numerous behind-the-casing crossflows in almost every well have resulted in a very complex conditions of remaining reserves. The conventional methods of production analysis and surveillance (well testing and production logging) do not provide a consistent picture of the current distribution and conditions of the remaining reserves and required a deeper and more complex analysis. Development Opportunities Management workflow was chosen for this particular holistic study, which includes a set of interconnected studies, field surveillance, geological and flow modelling and culminated in field development planning based on the digital asset twin. (Ganiev, B., 2021) Digital asset twin was constructed based on results of this workflow with a full-range economical model, flow simulation over the thoroughly calibrated fine-grid 3D dynamic model and production complication model (dynamic behavior of the fractures and behind-casing channeling). The 3D model has been calibrated on results of the cross-well pressure-pulse surveillance, reservoir-oriented production logging and was validated by the results of the drilling of the transition wells. The digital asset twin was used to find the optimal investment scenario based on multivariate calculations with the help of digital assistants. Due to simplicity of the user interface and client-server design, the digital twin was made available for various corporate engineers and managers without any modelling skills to play around with their own ideas on possible production/investment scenarios which gave another level of validation of the ultimate field development plan. All activities carried out within the digital twin automatically generate a complete package of investment metrics (NPV, PI, IRR, MIRR, Cash Flow and many correlation graphs) to assess the economic efficiency of each package and select the most appropriate solution for further ultimate choice. The approved scenario was based around drilling 6 producing side-tracks in specific locations/trajectories, performing workovers on specific offset injectors and re-scheduling of the production/injection rates in all block wells. The results of the field development's activities implementation will be the subject of a future publication.

scholarly journals Incremental and acceleration production estimation and their effect on optimization of well infill locations in tight gas reservoirs

2021 ◽  
Author(s):  
Atheer Dheyauldeen ◽  
Omar Al-Fatlawi ◽  
Md Mofazzal Hossain
Keyword(s):  
Transient Flow ◽  
Development Planning ◽  
Main Role ◽  
Gas Reservoirs ◽  
Type Curves ◽  
Field Development ◽  
Drilling Performance ◽  
Well Location ◽  
Infill Drilling ◽  
Tight Formations

AbstractThe main role of infill drilling is either adding incremental reserves to the already existing one by intersecting newly undrained (virgin) regions or accelerating the production from currently depleted areas. Accelerating reserves from increasing drainage in tight formations can be beneficial considering the time value of money and the cost of additional wells. However, the maximum benefit can be realized when infill wells produce mostly incremental recoveries (recoveries from virgin formations). Therefore, the prediction of incremental and accelerated recovery is crucial in field development planning as it helps in the optimization of infill wells with the assurance of long-term economic sustainability of the project. Several approaches are presented in literatures to determine incremental and acceleration recovery and areas for infill drilling. However, the majority of these methods require huge and expensive data; and very time-consuming simulation studies. In this study, two qualitative techniques are proposed for the estimation of incremental and accelerated recovery based upon readily available production data. In the first technique, acceleration and incremental recovery, and thus infill drilling, are predicted from the trend of the cumulative production (Gp) versus square root time function. This approach is more applicable for tight formations considering the long period of transient linear flow. The second technique is based on multi-well Blasingame type curves analysis. This technique appears to best be applied when the production of parent wells reaches the boundary dominated flow (BDF) region before the production start of the successive infill wells. These techniques are important in field development planning as the flow regimes in tight formations change gradually from transient flow (early times) to BDF (late times) as the production continues. Despite different approaches/methods, the field case studies demonstrate that the accurate framework for strategic well planning including prediction of optimum well location is very critical, especially for the realization of the commercial benefit (i.e., increasing and accelerating of reserve or assets) from infilled drilling campaign. Also, the proposed framework and findings of this study provide new insight into infilled drilling campaigns including the importance of better evaluation of infill drilling performance in tight formations, which eventually assist on informed decisions process regarding future development plans.

Artificial Lift Strategy Selection Within Field Development Planning (Russian)

2015 ◽  
Author(s):  
A. V. Alferov ◽  
A. G. Lutfurakhmanov ◽  
K. V. Litvinenko ◽  
S. E. Zdolnik
Keyword(s):  
Development Planning ◽  
Strategy Selection ◽  
Field Development ◽  
Artificial Lift

scholarly journals The Waitsia Field, onshore North Perth Basin, Western Australia

2016 ◽  
Vol 56 (1) ◽  
pp. 29 ◽  
Author(s):  
Neil Tupper ◽  
Eric Matthews ◽  
Gareth Cooper ◽  
Andy Furniss ◽  
Tim Hicks ◽  
...  
Keyword(s):  
Flow Characteristics ◽  
Development Planning ◽  
Upper Permian ◽  
Depth Interval ◽  
Lower Permian ◽  
Minimal Processing ◽  
Gas Field ◽  
Full Field ◽  
Field Development ◽  
Primary Porosity

The Waitsia Field represents a new commercial play for the onshore north Perth Basin with potential to deliver substantial reserves and production to the domestic gas market. The discovery was made in 2014 by deepening of the Senecio–3 appraisal well to evaluate secondary reservoir targets. The well successfully delineated the extent of the primary target in the Upper Permian Dongara and Wagina sandstones of the Senecio gas field but also encountered a combination of good-quality and tight gas pay in the underlying Lower Permian Kingia and High Cliff sandstones. The drilling of the Waitsia–1 and Waitsia–2 wells in 2015, and testing of Senecio-3 and Waitsia-1, confirmed the discovery of a large gas field with excellent flow characteristics. Wireline log and pressure data define a gross gas column in excess of 350 m trapped within a low-side fault closure that extends across 50 km2. The occurrence of good-quality reservoir in the depth interval 3,000–3,800 m is diagenetically controlled with clay rims inhibiting quartz cementation and preserving excellent primary porosity. Development planning for Waitsia has commenced with the likelihood of an early production start-up utilising existing wells and gas processing facilities before ramp-up to full-field development. The dry gas will require minimal processing, and access to market is facilitated by the Dampier–Bunbury and Parmelia gas pipelines that pass directly above the field. The Waitsia Field is believed to be the largest conventional Australian onshore discovery for more than 30 years and provides impetus and incentive for continued exploration in mature and frontier basins. The presence of good-quality reservoir and effective fault seal was unexpected and emphasise the need to consider multiple geological scenarios and to test unorthodox ideas with the drill bit.

Data Analytics into Hydraulic Modelling for Better Understanding of Well/Surface Network Limits, Proactively Identify Challenges and, Provide Solutions for Improved System Performance in the Greater Burgan Field

2021 ◽  
Author(s):  
Qasem Dashti ◽  
Saad Matar ◽  
Hanan Abdulrazzaq ◽  
Nouf Al-Shammari ◽  
Francy Franco ◽  
...  
Keyword(s):  
Production Management ◽  
Planning Process ◽  
System Optimization ◽  
Development Planning ◽  
Operating Conditions ◽  
Flow Assurance ◽  
Operational Parameters ◽  
Field Development ◽  
Hydraulic Models ◽  
Surface Network

Abstract A network modeling campaign for 15 surface gathering centers involving more than 1800 completion strings has helped to lay out different risks on the existing surface pipeline network facility and improved the screening of different business and action plans for the South East Kuwait (SEK) asset of Kuwait Oil Company. Well and network hydraulic models were created and calibrated to support engineers from field development, planning, and operations teams in evaluating the hydraulics of the production system for the identification of flow assurance problems and system optimization opportunities. Steady-state hydraulic models allowed the analysis of the integrated wells and surface network under multiple operational scenarios, providing an important input to improve the planning and decision-making process. The focus of this study was not only in obtaining an accurate representation of the physical dimension of well and surface network elements, but also in creating a tool that includes standard analytical workflows able to evaluate wells and surface network behavior, thus useful to provide insightful predictive capability and answering the business needs on maintaining oil production and controlling unwanted fluids such as water and gas. For this reason, the model needs to be flexible enough in covering different network operating conditions. With the hydraulic models, the evaluation and diagnosis of the asset for operational problems at well and network level will be faster and more effective, providing reliable solutions in the short- and long-terms. The hydraulic models enable engineers to investigate multiple scenarios to identify constraints and improve the operations performance and the planning process in SEK, with a focus on optimal operational parameters to establish effective wells drawdown, evaluation of artificial lifting requirements, optimal well segregation on gathering centers headers, identification of flow assurance problems and supporting production forecasts to ensure effective production management.

Utilizing Pseudo Well Connections to Simulate Multi-Stage Hydraulic Fracturing - Example Based On the Study of a Tight Gas Asset

2021 ◽  
Author(s):  
Aamir Lokhandwala ◽  
Vaibhav Joshi ◽  
Ankit Dutt
Keyword(s):  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Flow Simulation ◽  
Oil And Gas Industry ◽  
Development Plan ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Field ◽  
Field Development ◽  
Fracture Modeling

Abstract Hydraulic fracturing is a widespread well stimulation treatment in the oil and gas industry. It is particularly prevalent in shale gas fields, where virtually all production can be attributed to the practice of fracturing. It is also used in the context of tight oil and gas reservoirs, for example in deep-water scenarios where the cost of drilling and completion is very high; well productivity, which is dictated by hydraulic fractures, is vital. The correct modeling in reservoir simulation can be critical in such settings because hydraulic fracturing can dramatically change the flow dynamics of a reservoir. What presents a challenge in flow simulation due to hydraulic fractures is that they introduce effects that operate on a different length and time scale than the usual dynamics of a reservoir. Capturing these effects and utilizing them to advantage can be critical for any operator in context of a field development plan for any unconventional or tight field. This paper focuses on a study that was undertaken to compare different methods of simulating hydraulic fractures to formulate a field development plan for a tight gas field. To maintaing the confidentiality of data and to showcase only the technical aspect of the workflow, we will refer to the asset as Field A in subsequent sections of this paper. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The study involved comparing analytical fracture modeling, explicit modeling using local grid refinements, tartan gridding, pseudo-well connection approach and full-field unconventional fracture modeling. The result of the study was to use, for the first time for Field A, a system of generating pseudo well connections to simulate hydraulic fractures. The approach was found to be efficient both terms of replicating field data for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.

Sign in / Sign up

Export Citation Format

Share Document