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.

SUB-SURFACE UNCERTAINTY IN OIL FIELDS: LEARNINGS FROM EARLY PRODUCTION OF LEGENDRE OIL FIELDS

2003 ◽  
Vol 43 (1) ◽  
pp. 401
Author(s):  
R. Seggie ◽  
F. Jamal ◽  
A. Jones ◽  
M. Lennane ◽  
G. McFadzean ◽  
...  
Keyword(s):  
Planning Process ◽  
Development Planning ◽  
Oil Field ◽  
Production Performance ◽  
Oil Fields ◽  
High Rate ◽  
Secondary Development ◽  
North West ◽  
Field Development ◽  
Small Primary

The Legendre North and South Oil Fields (together referred to as the field) have been producing since May 2001 from high rate horizontal wells and had produced 18 MMBBL by end 2002. This represents about 45% of the proven and probable reserves for the field.Many pre-drill uncertainties remain. The exploration and development wells are located primarily along the crest of the structure, leaving significant gross rock volume uncertainty on the flanks of the field. Qualitative use of amplitudes provides some insight into the Legendre North Field but not the Legendre South Field where the imaging is poor. The development wells were drilled horizontally and did not intersect any fluid contacts.Early field life has brought some surprises, despite a rigorous assessment of uncertainty during the field development planning process. Higher than expected gas-oil ratios suggested a saturated oil with small primary gas caps, rather than the predicted under-saturated oil. Due to the larger than expected gas volumes, the gas reinjection system proved to have inadequate redundancy resulting in constrained production from the field. The pre-drill geological model has required significant changes to reflect the drilling and production results to date. The intra-field shales needed to be areally much smaller than predicted to explain well intersections and production performance. This is consistent with outcrop analogues.Surprises are common when an oil field is first developed and often continue to arise during secondary development phases. Learnings, in the context of subsurface uncertainty, from other oil fields in the greater North West Shelf are compared briefly to highlight the importance of managing uncertainty during field development planning. It is important to have design flexibility to enable facility adjustments to be made easily, early in field life.

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

4D RESERVOIR GEOCHEMISTRY AS AN AID TO INTERPRETING PRODUCTION DYNAMICS, LEGENDRE FIELD, EASTERN DAMPIER SUB-BASIN

2005 ◽  
Vol 45 (1) ◽  
pp. 117 ◽  
Author(s):  
R.C. Davis ◽  
K.R. Leischner ◽  
A.P. Murray ◽  
P.G. Ryles
Keyword(s):  
Gas Chromatography ◽  
Low Cost ◽  
Isotope Analysis ◽  
Development Planning ◽  
Geochemical Data ◽  
Fluid Composition ◽  
Operational Parameters ◽  
Compositional Gradient ◽  
Field Development ◽  
Low Viscosity

Reservoir geochemistry is a low cost, field development/appraisal tool resting on the principle that fluids isolated by flow barriers show slight compositional and/or isotopic differences. Such differences reflect subtle variations in charge history related to the location of the source kitchen and the source rock maturity at the time of expulsion, as well as post fill processes such as water washing and leakage. High resolution gas chromatography (HRGC), multi-dimensional gas chromatography (MDGC) and compound specific liquid and gas isotope analysis (CSIA) were performed on a time series of fluids, comprising stored oil from two drill stem tests, and produced fluids from six points in the Legendre field, Dampier Sub-basin, to investigate changes in fluid composition as production proceeded. The Legendre field contains high gravity (46° API), low viscosity oil, hosted in two culminations (North and South) in a thin, high quality clastic reservoir of Berriasian age. Fluids from different wells within the Northern accumulation are indistinguishable, indicating the oil is in communication and no compositional gradient exists. By contrast, compositional and isotopic differences between fluids from the Northern and Southern accumulations demonstrate that these pools are not in communication, and should therefore be treated separately from a development planning perspective.The differences in initial fluid compositions have been successfully used in conjunction with operational parameters to explain the increase in gas/oil ratio (GOR) of oil from Legendre South–2H that occurred after only 13 months of production. Comparison of pristine, preproduction separator samples with fluids collected after the observed increase in GOR, revealed that solution gas injected at Legendre West–1 has migrated rapidly into the southern part of the field. Integration of geochemical data with regional petroleum system concepts and a full 3D charge model has greatly assisted our understanding of these observations.

An Investigation of Mechanistic Foam Modeling for Optimum Field Development of CO2 Foam EOR Application

2021 ◽  
pp. 1-20
Author(s):  
Mohammad Izadi ◽  
Phuc H. Nguyen ◽  
Hazem Fleifel ◽  
Doris Ortiz Maestre ◽  
Seung I. Kam
Keyword(s):  
Oil Recovery ◽  
Population Balance ◽  
Development Planning ◽  
Operating Conditions ◽  
Sweep Efficiency ◽  
Population Balance Modeling ◽  
Field Development ◽  
Injection Condition ◽  
Gas Mobility ◽  
Injection Rates

Summary While there are a number of mechanistic foam models available in the literature, it still is not clear how such models can be used to guide actual field development planning in enhanced oil recovery (EOR) applications. This study aims to develop the framework to determine the optimum injection condition during foam EOR processes by using a mechanistic foam model. The end product of this study is presented in a graphical manner, based on the sweep-efficiency contours (from reservoir simulations) and the reduction in gas mobility (from mechanistic modeling of foams with bubble population balance). The main outcome of this study can be summarized as follows: First, compared to gas/water injection with no foams, injection of foams can improve cumulative oil recovery and sweep efficiency significantly. Such a tendency is observed consistently in a range of total injection rates tested (low, intermediate, and high total injection rates Qt). Second, the sweep efficiency is more sensitive to the injection foam quality fg for dry foams, compared to wet foams. This proves how important bubble-population-balance modeling is to predict gas mobility reduction as a function of Qt and fg. Third, the graphical approach demonstrates how to determine the optimum injection condition and how such an optimum condition changes at different field operating conditions and limitations (i.e., communication through shale layers, limited carbon dioxide (CO2) supply, cost advantage of CO2 compared to surfactant chemicals, etc.). For example, the scenario with noncommunicating shale layers predicts the maximum sweep of 49% at fg = 55% at high Qt, while the scenarios with communicating shale layers (with 0.1-md permeability) predicts the maximum sweep of only 40% at fg = 70% at the same Qt. The use of this graphical method for economic and business decisions is also shown, as an example, to prove the versatility and robustness of this new technique.

Challenges and Achievements of Drilling Record MRC Wells for Appraising and Developing an Offshore Tight Carbonate

2021 ◽  
Author(s):  
Mohand Ahmed Alyan ◽  
Jamie Scott Duguid ◽  
Atif Shahzad ◽  
Amna Ahmed Alobeidli ◽  
Alunood Khalifa Al Suwaidi ◽  
...  
Keyword(s):  
Planning Process ◽  
Cost Savings ◽  
Development Planning ◽  
Carbonate Reservoir ◽  
Surveillance Program ◽  
Reservoir Properties ◽  
Landing Point ◽  
Field Development ◽  
Capital Costs ◽  
Tight Carbonate

Abstract This paper describes the field development planning strategy for appraising and developing an offshore reservoir area via extended reach extra-long maximum reservoir contact laterals drilled from an artificial island. These single production and injection laterals are completed in excess of 20,000 ft on top of tens of thousands feet of drilled well path to reach the drain landing point. These laterals have a dual purpose, as in addition to reservoir appraisal, is to maximize the productivity and injectivity in an on-going development of a tight carbonate reservoir. The well planning process starts from a careful selection of reservoir target coordinates to maximize the oil in place being developed from the artificial island and to enable reservoir testing and appraisal. From this data, initial 3D well designs are generated based on island location and rig capability to ensure ability to drill and run completion to total depth. The generated well tracks are used in a reservoir model to forecast production uplifts and inflow/outflow profiling along laterals. A strategic drilling step-out program has been implemented to extend drilling reach and completion deployment incrementally along with a reservoir surveillance program. The program was designed with built-in risk mitigations for any potential drilling and completion issues. The implemented program has enabled drilling into new areas and testing the reservoir properties at a small incremental cost of extending horizontal laterals. This has led to huge cost savings versus a very expensive appraisal program from a wellhead platform that included drilling a new well in addition to topside facility changes and pipelines conversions along with associated maintenance costs. The data gathered from these wells have enabled reduction of geologic uncertainty and de-risking of future developments. As a result, the field development footprint of developed oil resources was extended by additional 20% without the requirement of building additional drilling structures. Additionally, there is a well count reduction via lateral extension thus leading to capital costs saving. There were initial challenges encountered during lower completion deployment but they were resolved successfully in subsequent wells. An outcome of this strategy was the successful drilling of maximum reservoir contact wells with tens of thousands feet of drilled well path to reach the drain landing point and then with single horizontal drains exceeding 20,000 ft. The drilled wells resulted in unprecedented records in UAE and globally in terms of well total length, horizontal drain length and completion deployment.

High Resolution Reservoir Simulator Driven Custom Scripts as the Enabler for Solving Reservoir to Surface Network Coupling Challenges

2021 ◽  
Author(s):  
Kanat Aktassov ◽  
Dauletbek Ayaganov ◽  
Kanat Imagambetov ◽  
Ruslan Alissov ◽  
Said Muratbekov ◽  
...  
Keyword(s):  
High Resolution ◽  
Development Planning ◽  
Gas Condensate ◽  
Reservoir Modeling ◽  
Network System ◽  
Field Development ◽  
Pressure Losses ◽  
Custom Made ◽  
Surface Network ◽  
Reservoir Simulator

Abstract This paper presents a practical methodology of optimizing and building a detailed field surface network system by using the high-resolution reservoir simulator driven custom-made Python scripts to efficiently predict the future performance of the vast oil and gas-condensate carbonate field. All existing surface hydraulic tables are quality checked and lifting issue constraints corrected. Pressure losses at the wellhead chokes incorporated into the high-resolution reservoir simulator in the form of equation by using the custom scripts instead of a table format to calculate gas rate dependent pressure losses more precisely. Consequently, all 400+ surface production system manifolds, pipes and well chokes Horizontal Flow Performance (HFP) tables are updated and coupled to the reservoir simulator through Field Management (FM) controller which in turn generates Inflow Performance Relationship (IPR) tables for the coupled wells and passes them to solve the network. The methodology described in this paper applied for a complex field development planning of the Karachaganak. At present, reservoir management strategy requires constant balancing effort to uniformly spread gas re-injection into the lower Voidage Replacement Ratio areas in the Upper Gas-Condensate part of the reservoir due to reservoir heterogeneity. Additionally, an increase in field and wells gas-oil ratio and water-cut creates bottlenecks in the surface gathering system and requires robust solutions to decongest the surface network. Current simulation tools are not always effective due longer run times and simulation instability due to complex network system. As a solution, project-specific network balancing challenges are resolved by incorporating custom-made scripts into the high-resolution simulator. Faster and flexible integrated model based on hydraulic tables reproduced the historical pressure losses of the surface pipelines at similar resolution and generated accurate prediction profiles in a twice-quicker time than existing reservoir simulator. Overall, this approach helped to generate more stable production profiles by identifying bottlenecks in the surface network and evaluate future projects with more confidence by achieving a significant CAPEX cost savings. The comprehensive guidelines provided in this paper can aid reservoir modeling by setting up flexible integrated models to account for surface network effects. The value of incorporating Python scripts demonstrated to implement non-standard and project specific network balancing solutions leveraging on the flexibility and the openness of the modelling tool.

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