Uncertainty Management Using Multi-Scenario Modeling in a Partially Appraised Field

2021 ◽  
Author(s):  
Sedoo Okechukwu ◽  
Adedoyin Orekoya ◽  
Precious Alamina ◽  
James Anyaehie ◽  
Adekoyejo Sonde ◽  
...  
Keyword(s):  
Development Strategy ◽  
Net Present Value ◽  
Oil And Gas ◽  
Energy Transition ◽  
Present Value ◽  
Model Concept ◽  
Field Development ◽  
Reservoir Architecture ◽  
Other Information ◽  
Hydrocarbon Fields

Abstract Considering the imminent end of the ‘easy oil’ era, the increasing demand for energy and the global push towards the energy transition, oil and gas companies are more than ever interested in sustainable ways to develop marginal and complex hydrocarbon fields economically, through the application of technology and maximization of data analysis. In small partially appraised fields where the cost of drilling an appraisal well could derail the project economics, it becomes necessary to sweat the limited data available for reservoir modelling. The uncertainty analysis must be robust enough to ensure that the adopted field development strategy would yield a positive net present value despite the wide uncertainties associated with the field. The conventional workflow for subsurface uncertainty modelling involves defining the uncertainty ranges of static and dynamic reservoir parameters based on a single reservoir model concept. This paper focuses on a marginal field case study where the multi scenario modelling approach was adopted. This approach considered alternate reservoir geologic concepts based on different interpretations of the reservoir architecture, taking full cognizance of the available data, reservoir uncertainties and regional geology knowledge. Field Alpha is located onshore of Niger Delta in Nigeria. The geologic setting consists mainly of multi-storey, complex channel-belt systems, incising through Shoreface deposits. The reservoir of interest is an elongated structure with only two well penetrations located at the opposite distal part of the structure. The key reservoir uncertainties are reservoir structure, architecture, connectivity, and property distribution. Two possible distinct architecture were interpreted based on regional correlation and seismic. This paper focuses on how the interpretations and other information informed a robust development strategy that yielded significant (30 %) reduction in development cost and positive net present value.

Reducing Cycle Time to First Oil for Deepwater Field Developments

2005 ◽  
Author(s):  
Beverley F. Ronalds
Keyword(s):  
Cycle Time ◽  
Fast Track ◽  
Net Present Value ◽  
Oil And Gas ◽  
Economic Returns ◽  
Present Value ◽  
Field Development ◽  
Wide Range ◽  
Primary Determinant ◽  
The Cost

The cycle time to first production is a primary determinant of the net present value (NPV) of an oil and gas asset. The cost, complexity and risk inherent in deepwater field developments, combined with the relative lack of experience in their execution, often encourages engineers to proceed cautiously in field development. However, a successful fast-track development schedule from discovery to first oil may bring significantly better economic returns. This paper investigates the key parameters influencing cycle time for different facility types, and outlines a wide range of measures that may be adopted to accelerate the time to first production.

Over-Design Versus Redesign As a Response to Future Requirements

2018 ◽  
Author(s):  
Jeffrey D. Allen ◽  
Phillip D. Stevenson ◽  
Christopher A. Mattson ◽  
Nile W. Hatch
Keyword(s):  
Development Strategy ◽  
Real World ◽  
Net Present Value ◽  
Design Approach ◽  
Development Cost ◽  
Present Value ◽  
Initial Release ◽  
Real World Applications ◽  
Product Development Strategy ◽  
Initial Research

Though little research has been done in the field of over-design as a product development strategy, an over-design approach can help products avoid the issue of premature obsolescence. This paper compares over-design to redesign as approaches to address the emergence of future requirements. Net present value (NPV) analyses of several real world applications are examined from the perspective of manufacturers and customers. This analysis is used to determine the conditions under which an over-design approach provides a greater benefit than a redesign approach. Over-design is found to have a higher net present value than redesign when future requirements occur soon after the initial release, discount rates are low, initial research and development cost or price is high, and when the incremental costs of the future requirements are low.

SURFACE FACILITIES FOR OILFIELDS IN THE SOUTH AUSTRALIAN SECTOR OF THE COOPER BASIN

1986 ◽  
Vol 26 (1) ◽  
pp. 470
Author(s):  
R.J. Scanlan ◽  
C.J. White
Keyword(s):  
Net Present Value ◽  
Task Force ◽  
Development Project ◽  
Project Planning ◽  
Present Value ◽  
The South ◽  
Field Development ◽  
Variable Nature ◽  
Wide Range ◽  
Cooper Basin

Delhi Petroleum Pty Ltd, as operator, has been responsible for the development of eight oilfields in the South Australian sector of the Cooper Basin since 1982. Some of these field developments are economically marginal, hence the need to optimise those aspects of the facilities which impact on the ongoing cost of production and the overall profitability. A phased development approach has evolved over the past three years to reduce the external financing requirements and to improve the certainty of the data used to define the key elements of each project.For the successful completion of the project a task force approach to project management is utilised, supported by the use of computerised project planning and control systems. Further, it is important to define and agree on the design criteria and philosophy for the project at the commencement, this providing a base by which to measure scope changes, and so that all concerned are working to a common goal.The use of economic analysis as a decision-making tool during all phases of the project assists the project team to home in on the key objective which is to maximise the project net present value. Comparative economics and sensitivity analysis are used at the conceptual stage to select the preferred development option, e.g. pipeline versus trucking.The design of surface facilities is dictated by a wide range of criteria including the above development philosophy. The variable nature of these criteria demonstrates that each new field development must normally be engineered individually to ensure the target of maximum net present value can be achieved.The Gidgealpa Crude Oil Development Project demonstrates the effectiveness of the above methodology and philosophies. The field was discovered in August 1984, and early production and trucking of oil commenced in January 1985 with 374 000 bbls produced prior to commissioning of the pipeline to Moomba in September 1985.

Economic Risk Analysis of Offshore Projects

1992 ◽  
Vol 114 (3) ◽  
pp. 165-174 ◽  
Author(s):  
E. M. Bitner-Gregersen ◽  
J. Lereim ◽  
I. Monnier ◽  
R. Skjong
Keyword(s):  
Net Present Value ◽  
Oil And Gas ◽  
Development Project ◽  
Oil Field ◽  
Economic Risk ◽  
Gas Field ◽  
Cost Overruns ◽  
Field Development ◽  
Project Assessment ◽  
Oil Field Development

A quantitative analysis of economic risk associated with large investments in offshore oil and gas field development and production is presented. The analysis is intended as a supporting tool in decision-making faced with uncertainty and risk, to study the effect of alternative decisions in an easy manner. The descriptors for the project assessment, such as the Internal Rate of Return (IRR) and Net Present Value (NPV) are applied. The study demonstrates first the impacts of early pilot production (EPP) prior to a main oil field development on the field economy of an oil field development and production installation. Furthermore, the result of cases which reflect relevant situations connected with cost overruns are presented, as well as derivation of rational decision criteria for termination/continuation of a project subjected to cost overruns. Finally, an oil field development project scheduling is demonstrated.

DEVELOPMENT OF THE IAGIFU-HEDINIA FIELD, PNG FOLD BELT: A MULTI-DISCIPLINARY RESERVOIR MANAGEMENT SUCCESS STORY

2000 ◽  
Vol 40 (1) ◽  
pp. 546
Author(s):  
J.J. Hebberger Jr. ◽  
S.P. Franklin ◽  
W.H. Uberawa ◽  
A.M.Pytte
Keyword(s):  
Seismic Data ◽  
Net Present Value ◽  
Reservoir Management ◽  
Oil Field ◽  
Fold Belt ◽  
Present Value ◽  
Success Story ◽  
Reserve Estimation ◽  
Field Development ◽  
Government Relations

Iagifu-Hedinia oil field was discovered in 1986 in the remote Highlands of PNG following a multi-year exploration effort. Exploration and subsequent field development of PNG's first petroleum export project were carried out without the aid of seismic data due primarily to the intense karst development in the area. Because of historically low oil prices and the remote and difficult environment, the decision to develop the field did not occur until late 1990. First oil was produced in June 1992, with successful development dependent upon an intense focus on cost management, land owner and government relations, and most critically an early commitment to active reservoir management by an empowered and multi-disciplinary reservoir management team (MDRM team). This MDRM team added as much as an incremental 70 MMBBL oil and US$240 million of net present value to the project. This resulted from its being given responsibility for reservoir characterisation, reserve estimation, economic analysis, and active reservoir management. At its core the team consisted of both petroleum engineers and earth scientists, but incorporated numerous other disciplines as they were needed. Key to this success was the support and endorsement of management to a truly empowered team.

FISCAL Optimizations to Achieve a Win-Win Gross Split Production Sharing Contract on Deep-Water Study Case Project

2021 ◽  
Author(s):  
A. H. Sasoni
Keyword(s):  
Net Present Value ◽  
Oil And Gas ◽  
Economic Modelling ◽  
Effective Tax Rate ◽  
Tax Rate ◽  
Field Development ◽  
Production Sharing ◽  
Cumulative Production ◽  
The Government ◽  
One Year

Indonesia has adopted a new oil and gas fiscal system called Gross Split PSC (Production Sharing Contract). The objective is to implement a better system for developing oil and gas projects in Indonesia, which will empower the government to secure a higher government take (GT) from the early stages of production and reduce bureaucracy for contractors. This individual project compares the new PSC scheme and the Traditional PSC system using deterministic sensitivity analysis to determine the most optimal fiscal terms under the Gross Split PSC. The discussion includes profitability index, such as the government’s share of gross revenue (GSGR), project’s net present value (NPV) and the internal rate of return (IRR). The work was carried out from both the contractor’s and government’s perspective in an Indonesian Petroleum Association (IPA) simulation gas case study field development in deep offshore. The results of the economic modelling analysis provides that Gross Split PSC will have the same IRR as the Traditional PSC if the project is accelerated for one year, receives a 5% deductible effective tax rate and gets an additional progressive split of cumulative production.

An Improved Methodology for Gas-Condensate Cluster Evaluations under Uncertainty

2021 ◽  
Author(s):  
Sergei Igorevich Melnikov ◽  
Nikita Vladimirovich Vershigora ◽  
Alexander Alexandrovich Groo ◽  
Denis Sergeevich Grigorev ◽  
Pavel Yurievich Kiselev ◽  
...  
Keyword(s):  
Development Strategy ◽  
Oil And Gas ◽  
Business Case ◽  
Oil Field ◽  
Gas Condensate ◽  
Gas Field ◽  
Field Development ◽  
Asset Development ◽  
Additional Value ◽  
Probabilistic Nature

Abstract A decision to buy oil and gas assets requires a project evaluation (PE) aimed at integrated calculation of numerous possible scenarios of asset development, based on the uncertain resource values, variety of geological exploration program events, the most preferable decisions about the oil field development in the current economic conditions. The vast amount of calculations determined by the probabilistic nature of the PE and specific timeframes require optimization of the current approaches based on the balance between accuracy and time. This issue is particularly relevant for the evaluation and analysis of gas or gas-condensate field cluster as the profitability of the project can be concentrated in the asset integration into one production cluster. Such option as well as proposal to gather separate fields to the common infrastructure, sequence of fields development with different geological and physical characteristics, calculations of a large number of synergy options, etc. require the multi-disciplinary team to think outside the box while searching for a business case. Thus, this paper is aimed to improve current approaches and the current tools adaptation which will be used to drastically automate cross-functional probability estimate of gas field cluster with technical and economic justification of sustainable integrated solutions. The results were successfully validated within PE of several perspective gas condensate projects focused on the possibility of integration of the fields into a single cluster that creates additional value from the optimization of the project solutions (exploration, development strategy, gathering and transportation of hydrocarbons, monetization of the products) equal to tens of billions of rubles in a limited period of time.

Re-Fracturing in Eagle Ford and Bakken to Increase Reserves and Generate Incremental NPV - Field Study

2015 ◽  
Author(s):  
YagnaDeepika Oruganti ◽  
Rohit Mittal ◽  
Cameron J. McBurney ◽  
Alberto Rodriguez
Keyword(s):  
Development Strategy ◽  
Net Present Value ◽  
Performance Metrics ◽  
Cost Savings ◽  
Horizontal Wells ◽  
Hydraulic Fractures ◽  
Eagle Ford ◽  
Field Development ◽  
Before And After ◽  
Alternative Field

Abstract Due to the tight nature of the matrix in shale plays, the drainage area does not extend far into the reservoir and is defined by the shape and size of the hydraulic fractures. As a consequence of this, wells typically exhibit steep decline rates and one of the prevalent ways to arrest the decline of a field is to drill and complete more wells. However, re-fracturing is slowly gaining a foothold in the industry, and our study has shown tremendous re-frac potential in the Bakken and Eagle Ford. In this study, we analyzed horizontal wells from the Bakken and Eagle Ford to identify existing re-fractured wells and estimated incremental recovery, followed by an economic analysis, to show re-fracturing as a viable alternative to drilling new wells. Production and completions data was retrieved from public sources for all horizontal wells in the Bakken and the Eagle Ford formations, and a proprietary algorithm was applied to identify wells with a production signature that is consistent with a recompletion event. These wells were individually screened and confirmed as being re-fractured or not. Production metrics were defined to understand the performance of the wells before and after re-fracturing. Cross plots were made between these parameters to understand trends between the ratios of production decline rates and b-factors before and after re-fracturing, taking into account the time of re-completion. Decline curves were fit to the production of these wells to estimate the incremental estimated ultimate recovery (EUR) upon re-fracturing, and a net present value (NPV) analysis was done to determine commercial viability. A majority of the identified potentially re-fractured wells had positive incremental NPV based on the EUR increase, which was 53% and 69%, on an average, for the Eagle Ford and Bakken respectively. From the existing re-fractured wells that were analyzed, it was found that there was no discernible correlation between the time an operator produces a well before being refractured and the various performance metrics that were analyzed. Also, good decline curve fits were found without changing the b-factors post-refrac and secant decline rates were typically lower after re-fracturing. The results show the potential of re-completing wells and increasing reserves without drilling new wells based on actual field examples, showing an alternative field development strategy to the current practice of replacing older wells with newly drilled ones. Also, if re-fracturing is to be implemented on a larger scale, wells must be completed so as to make subsequent recompletions much easier, thereby encouraging use of novel casing and diverting agent technologies. Positive economics shows the huge potential of cost savings with re-stimulation and makes a ‘second wave’ of Eagle Ford/Bakken production possible.

scholarly journals SELECTION OF ALTERNATIVES FOR OIL FIELD DEVELOPMENT BY GENETIC ALGORITHMS

2002 ◽  
Vol 1 (2) ◽  
Author(s):  
Yvan J. Túpac ◽  
Marley Maria B.R. Vellasco ◽  
Marco Aurélio C. Pacheco
Keyword(s):  
Genetic Algorithm ◽  
Net Present Value ◽  
Oil Field ◽  
Oil Reservoir ◽  
Present Value ◽  
Field Development ◽  
Oil Field Development ◽  
The One ◽  
Genetic Algorithm Model ◽  
Selection Of

This paper presents a Genetic Algorithm application for selecting the best alternative for oil field development under certainty. The alternatives in this study are related to the arrangement of wells in a known and delimited oil reservoir and serve as a basis for calculating the net present value, which is used to assess the optimization process: the optimal alternative is the one that maximizes the Net Present Value of the field. The results obtained have revealed that the Genetic Algorithm model was able to find good alternatives for the oil field development, achieving good results for the Net Present Value.

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