scholarly journals EPS Conceptual Design for GoM Deepwater Fields

2010 ◽  
Author(s):  
Michael Choi ◽  
Andrew Kilner ◽  
Hayden Marcollo ◽  
Tim Withall ◽  
Chris Carra ◽  
...  
Keyword(s):  
Conceptual Design ◽  
Oil And Gas ◽  
Cost Effective ◽  
Test System ◽  
Well Test ◽  
Well Performance ◽  
Compressed Natural Gas ◽  
Full Field ◽  
Field Development ◽  
Early Production

To avoid making billion dollar mistakes, operators with discoveries in deepwater (∼3,000m) Gulf of Mexico (GoM) need dependable well performance, reservoir response and fluid data to guide full-field development decisions. Recognizing this need, the DeepStar consortium developed a conceptual design for an Early Production System (EPS) that will serve as a mobile well test system that is safe, environmentally friendly and cost-effective. The EPS is a dynamically positioned (DP) Floating, Production, Storage and Offloading (FPSO) vessel with a bundled top tensioned riser having quick emergency disconnect capability. Both oil and gas are processed onboard and exported by shuttle tankers to local markets. Oil is stored and offloaded using standard FPSO techniques, while the gas is exported as Compressed Natural Gas (CNG). This paper summarizes the technologies, regulatory acceptance, and business model that will make the DeepStar EPS a reality. Paper published with permission.

Floating early production systems

2011 ◽  
Vol 51 (2) ◽  
pp. 671
Author(s):  
Hayden Marcollo ◽  
Christopher Carra
Keyword(s):  
Deep Water ◽  
Oil And Gas ◽  
Production Systems ◽  
Rate Capability ◽  
Full Field ◽  
Associated Gas ◽  
Field Development ◽  
Sea Bottom ◽  
Early Production ◽  
High Level

Floating early production systems (FEPS) are becoming more important to the successful exploitation of Australia's deep water oil and gas. Importantly, FEPS help oil and gas operators reduce deep water full field development risk, as uncertainty in the reservoir characteristics are reduced by obtaining dynamic data (that is, partially producing some of the reservoir). This paper will present a review of existing FEPS that are now in use or have previously been in use worldwide and will discuss where they are headed in the future. The paper focuses on: The selection of the floating and subsea-vessel, mooring, riser, mechanical connection, etcetera; Technology presently available; and, Addressing the requirements in situations where new floating and subsea technology is needed. The qualification limits of existing technology will be discussed in the context of what systems are ready and off-the-shelf for operators to make use of now. The choice of appropriate FEPS will be discussed as a function of: proximity to pipeline infrastructure, potential production rate, capability to re-inject associated gas, prevailing variation in year-round environmental conditions, waterdepth, and, geotechnical description of sea bottom. A high level conceptual case study showing typical costs for the implementation of a deep water FEPS will be presented as a way of understanding the potential upside and downside exposure for an operator considering undertaking a deep water FEPS program.

Abandonment Best Practices in Unitised Area for Wells and Facilities Straddling Two Countries in Malay Basin: A Case Study

2021 ◽  
Author(s):  
Kumar Nathan ◽  
M Arif Iskandar Ghazali ◽  
M Zahin Abdul Razak ◽  
Ismanto Marsidi ◽  
Jamari M Shah
Keyword(s):  
Oil And Gas ◽  
Late Life ◽  
Cost Effective ◽  
Successful Outcome ◽  
Maintenance Cost ◽  
Gas Field ◽  
Field Development ◽  
Host Government ◽  
Cycle Oil

Abstract Abandonment is considered to be the last stage in the oil gas field cycle. Oil and gas industries around the world are bounded by the necessity of creating an abandonment program which is technically sound, complied to the stringent HSE requirement and to be cost-effective. Abandonment strategies were always planned as early as during the field development plan. When there are no remaining opportunities left or no commercially viable hydrocarbon is present, the field need to be abandoned to save operating and maintenance cost. The cost associated on abandonment can often be paid to the host government periodically and can be cost recoverable once the field is ready to be abandoned. In Malaysia, some of the oil producing fields are now in the late life of production thus abandonment strategies are being studied comprehensively. The interest of this paper is to share the case study of one of a field that is in its late life of production and has wells and facilities that planned to be abandon soon. The abandonment in this field is challenging because it involves two countries, as this field is in the hydrocarbon structure that straddling two countries. Series of techno-commercial discussion were held between operators of these two countries to gain an integrated understanding of the opportunity, defining a successful outcome of the opportunity and creating an aligned plan to achieve successful abandonment campaign. Thus, this paper will discuss on technical aspects of creating a caprock model, the execution strategies of abandoning the wells and facilities and economic analysis to study whether a joint campaign between the operators from two countries yields significantly lower costs or otherwise.

Implications of accurate geomechanical modelling and systematic core testing for sanding evaluation and sand control decisions – a case study from Perth Basin

2020 ◽  
Vol 60 (1) ◽  
pp. 267
Author(s):  
Sadegh Asadi ◽  
Abbas Khaksar ◽  
Mark Fabian ◽  
Roger Xiang ◽  
David N. Dewhurst ◽  
...  
Keyword(s):  
Management Strategies ◽  
Mechanical Tests ◽  
Well Test ◽  
Sand Production ◽  
Gas Field ◽  
Stress Regime ◽  
Full Field ◽  
Field Development ◽  
Sand Control ◽  
Rock Mechanical Properties

Accurate knowledge of in-situ stresses and rock mechanical properties are required for a reliable sanding risk evaluation. This paper shows an example, from the Waitsia Gas Field in the northern Perth Basin, where a robust well centric geomechanical model is calibrated with field data and laboratory rock mechanical tests. The analysis revealed subtle variations from the regional stress regime for the target reservoir with significant implications for sanding tendency and sand management strategies. An initial evaluation using a non-calibrated stress model indicated low sanding risks under both initial and depleted pressure conditions. However, the revised sanding evaluation calibrated with well test observations indicated considerable sanding risk after 500 psi of pressure depletion. The sanding rate is expected to increase with further depletion, requiring well intervention for existing producers and active sand control for newly drilled wells that are cased and perforated. This analysis indicated negligible field life sanding risk for vertical and low-angle wells if completed open hole. The results are used for sand management in existing wells and completion decisions for future wells. A combination of passive surface handling and downhole sand control methods are considered on a well-by-well basis. Existing producers are currently monitored for sand production using acoustic detectors. For full field development, sand catchers will also be installed as required to ensure sand production is quantified and managed.

Thermal Benefits With Subsea Heat Bank

2002 ◽  
Author(s):  
Kristin Falk ◽  
Rune Killie ◽  
Svein Ha˚heim ◽  
Per Damsleth
Keyword(s):  
Oil And Gas ◽  
Hydrate Formation ◽  
Cost Effective ◽  
Effective Field ◽  
Production Equipment ◽  
Cfd Simulations ◽  
Field Development ◽  
Gas Hydrate Formation ◽  
Computational Fluid Dynamics Cfd ◽  
Cfd Analyses

Subsea production of oil and gas involves structures on the seabed such as manifolds and X-mas trees that require thermal insulation of piping and valves to avoid gas hydrate formation. The insulation is expensive and time consuming to apply yet may still leave areas with inadequate protection. These “cold spots” accelerate the cooling during a production shutdown. A Heat-Bank concept is developed as an alternative to conventional insulation. The entire subsea structure is covered with an insulated shell. During shutdowns the heated fluid inside the cover keeps the production equipment warm over a prolonged period before hydrates start to form. Computational Fluid Dynamics (CFD) simulations are used to quantify the heat loss effects of natural convection and leakage through openings in the cover. The CFD analyses demonstrate the relative performance of the concept compared to the traditional method of insulating individual piping components. Application of the Heat-Bank concept opens new possibilities for environmentally friendly and cost-effective field development, especially for deep water.

Advanced Gas While Drilling GWD Comparison with Pressure Volume Temperature PVT Analysis to Obtain Information About the Reservoir Fluid Composition, a Case Study from East Kuwait Jurassic Reservoir

2021 ◽  
Author(s):  
Mohammad J. Ahsan ◽  
Shaikha Al-Turkey ◽  
Nitin M. Rane ◽  
Fatemah A. Snasiri ◽  
Ahmed Moustafa ◽  
...  
Keyword(s):  
Real Time ◽  
Oil And Gas ◽  
Compositional Analysis ◽  
Fluid Composition ◽  
Well Test ◽  
Drilling Mud ◽  
Strong Base ◽  
Field Development ◽  
Gas Drilling ◽  
Reservoir Fluid

Abstract Objectives/Scope The acquisition of mud gas data for well control and gathering of geological information is a common practice in oil and gas drilling. However, these data are scarcely used for reservoir evaluation as they are presumably considered as unreliable and non-representative of the formation content. Recent development in gas extraction from drilling mud and analyzing equipment has greatly improved the data quality. Combined with proper analysis and interpretation, these new datasets give valuable information in real-time lithological changes, hydrocarbons content, water contacts and vertical changes in fluid over a pay interval. Methods, Procedures, Process Post completion, Mud logging data have been compared with PVT results and they have shown excellent correlation on the C1-C5 composition, confirming the consistency between gas readings and reservoir fluid composition. Having such information in real time has given the oil company the opportunity to optimize its operations regarding formation evaluation, e.g downhole sampling, wireline logging or testing programs. Formation fluid is usually obtained during well tests, either by running downhole tools into the well or by collecting the fluid at surface. Therefore, its composition remains unknown until the arrival of the PVT well test results. This case intends to use mud gas information collected while drilling to predict information about the reservoir fluid composition in near real time. To achieve this goal we compared mud gas data collected while drilling with reservoir fluid compositional results. Pressure volume temperature (PVT) analysis is the process of determining the fluid behaviors and properties of oil and gas samples from existing wells. Results, Observations, Conclusions The reason any oil and gas company decides to drill a well is to turn the project into an oil-producing asset. But the value of the oil extracted from a single well is not the same as the value of the oil produced from another. The makeup of the oil, which can be determined from the compositional analysis, is an important piece of the equation that determines how profitable the play will be. The compositional analysis will determine just how much of each type of petroleum product can be produced from a single barrel of oil from that wells. Novel/Additive information Formation samples were obtained from offset wells in the Marrat Formation. These datasets gave valuable indications on fluid properties and phase behavior in the reservoir and provided strong base for reservoir engineering analysis, simulation and surface facilities design. The comparison of the gas data to PVT results gives a good match for reservoir fluid finger print, early acquisition of this data will help for decision enhancement for field development.

Flowline Bundle Concept for JZ 9-3 Field Development

2014 ◽  
Author(s):  
Jing Cao ◽  
Yong Sha ◽  
Liwei Li
Keyword(s):  
Engineering Design ◽  
Corrosion Protection ◽  
Thermal Performance ◽  
Oil And Gas ◽  
Cost Effective ◽  
Development Project ◽  
Bohai Bay ◽  
Effective Solution ◽  
Field Development ◽  
Protection Potential

Flowline bundle system consisting of carrier pipe, sleeve pipe and internal flowlines offers smart solution for the infield transportation of oil and gas. Due to its features, flowline bundle offers a couple of advantages over conventional flowline in particular for cases where multi-flowlines and high thermal performance are of great interests. The main benefits and advantages of such system include excellent thermal performance to prevent wax formation and hydrates, multiple bundled flowlines, mechanical and corrosion protection, potential reuse, fabricated onshore, as well as towing installation without the requirement of professional pipelay vessel etc. Flowline bundle system can be a smart solution for certain applications, which can be safe and cost effective solution. The objective of this paper is to present the feasibility study of flowline bundle concept for the JZ 9-3 West Development project in Bohai Bay, Offshore China. This study covers engineering design, fabrication, and offshore towing installation. Design and installation results have been presented and the feasibility of flowline bundle concept has been fully demonstrated for the JZ 9-3 West field development.

Insights into Khuff Oil Rim Development in Sultanate of Oman from Extensive Drilling and Well Testing Operations

2021 ◽  
Author(s):  
Tingting Zhang ◽  
Arun Kumar ◽  
Rashid Al Maskari ◽  
Maryam Musalami ◽  
Sumaiya Habsi
Keyword(s):  
Management Plan ◽  
Productivity Index ◽  
Well Testing ◽  
Flow Profile ◽  
Well Test ◽  
Sultanate Of Oman ◽  
Full Field ◽  
Associated Gas ◽  
Field Development ◽  
Rock Types

Abstract The Yibal Khuff project is a mixed oil-rims, associated gas, and non-associated gas development in highly fractured tight carbonate reservoirs. Rock types and fractures vary widely with significant contribution to flow. In the east segment of the field, 22 horizontal oil producers targeting K2 reservoir have been pre-drilled and tested extensively. The integration of well logs, borehole image data (BHI), well test data and production logs provide key insights into reservoir productivity and the development of a robust well and reservoir management plan, ready for start-up of the field in 2021. A log-based approach was used to classify the reservoir into three main rock types (RRT). Fractures were classified, and high impact fractures were identified. Reservoir flow profile based on noise and temperature logs was established and used in combination with fracture data and cement bond logs in understanding flow conformance and behind casing flow. A large variation in productivity index has been observed, from tight to highly productive wells. Different ways have been explored to establish the link between productivity index, fracture production, and matrix production by rock types. This is the first full field development in the Khuff formation in Sultanate of Oman. The results will benefit a wider audience. A holistic approach was taken to explore the link between well deliverability and nature of a complex geology. The outcome is a robust operating envelope and well, reservoir and facilities management (WRFM) plan, clearly driven by understanding of subsurface risk and opportunities.

The Selection and Optimum Well Testing Practices to Achieve Zero Flaring & Venting in Malaysian Water for a Petronas Field Development

2021 ◽  
Author(s):  
Adhi Naharindra ◽  
Zalina Ali ◽  
Nik Fazril Ain Sapi’an ◽  
Latief Riyanto ◽  
Fuziana Tusimin ◽  
...  
Keyword(s):  
Environmental Impact ◽  
Oil And Gas ◽  
Oil Field ◽  
Testing System ◽  
Well Testing ◽  
Well Test ◽  
Flow Lines ◽  
Field Development ◽  
Well Completion ◽  
Production Facilities

Abstract Increased HSE concerns and global economic efficiency from well testing activities especially on its environmental impact have left several oil and gas industries’ facing critical challenges to develop and monetize oil reserves. Some of these challenges include handling well effluents from well test unloading operations after well completion with high contaminants such as H2S and CO2 which will exacerbate environmental impact to safety, pollution, and oil spill risks. In addition, mitigation to environmental impact will be constrained to limited deck space and topside loads for offshore wellhead facilities and eventually restricts the footprint of well test unloading equipment. The scope of the paper is to examine the evolution of well deliverability testing from conventional well test facilities’ flaring practices to contemporary smokeless and zero flaring operations applied in a giant sand stones oil field in Malaysian water, which is surrounded by a world class environmentally protected marine and coastal ecosystem. The zero-flaring approach allows a demonstration of the safety & emission reduction, cost saving, technical viability, and economic benefits over traditional flaring techniques for 20 to 30 well testing during the life of field. Previous wells clean up method require flaring of oil and gas before the production facilities and flow lines were operational.commissioned. The application of environment friendly well testing system using the completed flow lines and production facilities enable zero-flaring option to be technically and economically viable. Zero-flaring well testing system provides several attractive benefits, with potential reduction in flaring equivalent of ±1000 barrels of oil, pollution avoidance, 40 - 50% schedule reduction and over 40% reduction in total project costs for the field development..

Solving the Problem of Operational Accounting of Well Drilling Results in a Full-Scale Model of Unique Gas Condensate Fields

2021 ◽  
Author(s):  
Andrey Viktorovich Poushev ◽  
Ruslan Railievich Mangushev ◽  
Sergey Anatolievich Yakimov
Keyword(s):  
Decision Making ◽  
Oil And Gas ◽  
Flow Simulation ◽  
Simulation Models ◽  
Gas Production ◽  
Scale Model ◽  
New Production ◽  
Full Field ◽  
Field Development ◽  
Field Static

Abstract Today, strategic planning of field development is based on full-field static and flow simulation models which are regularly updated as part of field surveillance programs and by integrating the actual results of drilling and testing of new production and exploration wells and integrated interpretation of seismic surveys and reservoir core and fluid laboratory analyses. One of the key factors for the success of investment projects is how quick and flexible the decision-making process is. Therefore, in modern conditions, prompt integration of new data into full-field flow simulation models followed by their processing, analysis, and decision-making on adjusting the strategic goals is of particular relevance for oil and gas production companies. For unique multi-reservoir fields containing dozens of reservoirs, hundreds of accumulations and wells, it is hardly possible to promptly update full-field static and flow simulation models within less than 6-12 months, therefore, the decisions are made in the absence of up-to-date models, which may lead to poor quality of production forecasts. The purpose of the study was to develop an approach to the modeling of unique fields, which would allow prompt integration of new data in a full-field flow simulation model while keeping the level of detail without significant time input.

scholarly journals FDPSOs: The new reality, and a game-changing approach to field development and early production systems

2011 ◽  
Vol 133 (05) ◽  
pp. 54-62
Keyword(s):  
Production System ◽  
Production Systems ◽  
Step Change ◽  
Full Field ◽  
Field Development ◽  
Deepwater Drilling ◽  
Drilling Rig ◽  
Key Variables ◽  
Early Production ◽  
Game Changer

This article summarizes development of the Azurite field as a way of providing context for evolution of the Floating, Drilling, Production, Storage and Offloading (FDPSO) concept. It also reflects on the project’s technical and economic drivers that led the Azurite project team to select the FDPSO concept. The paper also highlights other application for FDPSOs and discusses some of the key variables that determine the suitability of the FDPSO concept for use in field developments. The step change in economics afforded by the incorporation of a drilling rig onboard a conventional FPSO brings new hope to fields of similar geometry and in similar environments that heretofore were considered marginally economic or uneconomic. The FDPSO concept also has application as an early production system, in advance of full-field developments. The concept has tremendous potential as a ‘game changer’ for field developments, whether it is employed to unlock the value of marginal fields in deepwater – even in a low oil price environment – or as an early production system. As the concept employs a drilling rig onboard the vessel, traditional challenges regarding deepwater drilling rig day rates and availability are eliminated.

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