Oil Field Development Project Research Articles

A Comprehensive Asset Evaluation Method for Oil and Gas Projects

The rapid and accurate evaluation of oil and gas assets, specifically for new development projects, poses a significant challenge due to the various project types, limited data availability, brief periods for assessment and decision making, and constraints arising from varying contractual and taxation conditions, political stability, and societal factors. This study leverages the grading standards of the evaluation index system for new oil and gas field development projects, along with relevant mathematical theories and methods for project evaluation and optimization. We developed an asset evaluation approach for new oil and gas projects by analyzing the assets of six new oil and gas field development projects in Brazil. This analysis resulted in the grading and ranking of new projects, and we tested and demonstrated four asset optimization techniques. After a comparative analysis with conventional evaluation results, we established an oil and gas project asset optimization approach centered on the cloud model comprehensive evaluation and linear weighted ranking, exhibiting Kendall’s tau coefficient of 0.8667 with conventional methods. The findings suggest that the combination of the cloud model comprehensive evaluation method with the linear weighted ranking method can facilitate asset optimization for oil and gas field development projects, meeting the practical needs for fast selection among various new projects. Furthermore, this research offers a technical and theoretical foundation for rapid evaluation and decision making regarding new assets.

Iranian output on the rise as exports continue to flow despite sanctions

Oil and Energy TrendsVolume 48, Issue 6 p. 8-9 LOOKING AHEAD Iranian output on the rise as exports continue to flow despite sanctions First published: 18 June 2023 https://doi.org/10.1111/oet.13023Read the full textAboutPDF ToolsRequest permissionExport citationAdd to favoritesTrack citation ShareShare Give accessShare full text accessShare full-text accessPlease review our Terms and Conditions of Use and check box below to share full-text version of article.I have read and accept the Wiley Online Library Terms and Conditions of UseShareable LinkUse the link below to share a full-text version of this article with your friends and colleagues. Learn more.Copy URL No abstract is available for this article. REFERENCES 1 Time. President Trump Pulls U.S. Out of ‘Defective’ Iran Nuclear Deal. https://time.com/5269746/donald-trump-iran-nuclear-deal-macron/. Accessed June 1, 2023 2 BBC News. Iran's Ebrahim Raisi: The hardline cleric who became president. https://www.bbc.co.uk/news/world-middle-east-57421235. Accessed June 1, 2023 3 Phase 11 of South Pars is the last undeveloped project in the massive reservoir and should be onstream before winter 2024, adding 11 mn m3/d to production. 4 Shana Petro Energy Information Network. Sohrab oil field development project operations start. https://en.shana.ir/news/471747/Sohrab-oil-field-development-project-operations-start. Accessed June 1, 2023 Volume48, Issue6June 2023Pages 8-9 ReferencesRelatedInformation

A novel design for a selective fluid inflow control device

In oil field development projects, reservoir heterogeneity can easily to produce water ridge problems, resulting in premature water discovery in wells. Selective inflow control devices can effectively slow water ridging. However, there are relatively few studies on inflow control devices for medium and low viscosity crude oil with viscosity below 50 mPa s. In this study, a new type of selective inflow control device was designed for wells with low oil viscosities, and its performance was analyzed using experimental and numerical simulation software. The effects of the structural (inner inlet) and fluid parameters (viscosity, flow rate and water cut) on the performance of the selective inflow control device were simulated. The experimental results show that the flow pressure loss is still low when the oil viscosity is 32 mPa s, and it can achieve a more considerable flow difference between oil and water at a larger flow rate. The simulation results show that the best suitable viscosity of the device is 50 mPa s. The internal structure of the tool has considerable influence on the pressure loss and flow-field distribution under low-viscosity conditions. Under high viscosity conditions, the pressure loss gradually exhibited a linear trend, and the influence of the internal structure decreased. When the flow rate is greater than 2 m³/d, the internal flow field distribution is more affected by the viscosity than the flow rate.

Prediction of CO2 storage performance in reservoirs based on optimized neural networks

Accurate prediction of CO2 geological storage performance is of great guiding significance for oilfield development and management. The use of artificial neural networks is an effective method; however, insufficient data and certain errors caused by difficulties encountered during the measurement process make the traditional neural network fall into local optimization or overfitting. Therefore, in this study an optimized back propagation (BP) neural network based on the lion swarm optimization (LSO) algorithm was proposed. Firstly, the LSO algorithm was improved by combining a tent chaotic map and differential evolution to enhance its optimization capability. Secondly, the improved algorithm was used to obtain the optimal initial weights and thresholds of BP neural networks. Finally, by using the normalized sample data obtained by numerical simulation, five dimensionless variables were introduced to predict the CO2 storage performance in reservoirs. Experimental results demonstrated that the proposed model yields a faster convergence speed and higher prediction accuracy compared with four existing neural networks. The root mean square errors on the training and test sets were 0.0234 and 0.0254, respectively, and the absolute error of more than 95% of the data was within 5%, which shows that the proposed method is feasible and effective in predicting the CO2 storage performance and can serve as a good guide in oilfield development projects.

Optimization of Exploration and Production Sharing Agreements Using the Maxi-Min and Nash Solutions

Cooperation between supply chain partners in the oil industry is essential, especially when oil prices suffer from fluctuations that affect the profitability of each party. An essential task in oil field development projects is to create an optimum agreement between the national oil company and the international oil company to guarantee agreement optimization. In this paper, the national oil company is the first party (FP) and the international oil company is the second party (SP). The paper’s purpose is to investigate the use of game theory to obtain the best agreement between the FP and SP in order to enhance the cooperation and reduce conflict. In this paper, Nash and Maxi-min solutions have been applied for the first time in a special type of petroleum agreement, called exploration and production sharing agreements (EPSA). This is conducted for a case study in Libya. The study considers nine negotiation factors (issues) in the EPSA, which are the share percent, the four “A” factors, and the four “B” factors, which are usually affected by the fluctuations of oil prices; and the study investigates their effect on the total payoff function, the net present value (NPV), and internal rate of return (IRR) for both parties. The Maxi-min solution has shown an improvement in the NPV and IRR of the SP, where NPV increased from USD 148 million to USD 195 million, and IRR from 15.65% to 17.01%. The Nash solution has shown a little more improvement than the Maxi-min solution in the NPV and IRR for the SP, where the NPV and IRR have increased from USD 148 million to USD 222 million and from 15.65% to 17.94%, respectively.

Экономическая оценка проектов разработки месторождений углеводородного сырья в условиях северных районов добычи с применением бинарного и реверсированного дисконтирования.

The conversion from the development of large deposits to unconventional, small and Arctic deposits of hydrocarbon raw materials in the Russian requires oil and gas companies improving the quality of the economic justification of projects, including cost-effectively recoverable reserves. For this reason, the development of the discounted cash flow (DCF) method for economic evaluation of oil and gas projects is required. The purpose of the study was to develop a methodological approach to the economic evaluation of oil and gas projects. The disadvantages of the DCF model in the economic evaluation of oil and gas field development projects are analyzed, a comparative analysis of project evaluation methods through the use of binary and reverting discounting models is performed. The authors justified the choice of a risk-free discount rate for project outflows and dynamically changing values of discount rates for project cash inflows for the evaluation of oil and gas projects, taking into account their identified features. The application of the developed methodological approach, both at the pre-project phase and during the operation of the field, will allow oil and gas companies to justify the magnitude of commercially exploitable reserves and indicators of the economic efficiency of the project due to more correct risk accounting. The developed methodological approach has been approved on the example of the Novoportovskoye field development project.

Risk Management in Oil and Gas Field Development Project with Marginal Resources: A Case in Mature Field in East Kalimantan

The oil and gas industry and risks are very related to each other. There are several risks known in this industry, from economic risks, political risks, environmental and safety risks, up to geological risks itself. Because oil and gas are a non-renewable source of energy, the more mature an oil and gas field is, the risks for the company to develop a project investment may be lower and higher at the same time. Entering its declining phase, PT MNO who is trusted to operate an ex-termination oil and gas field in East Kalimantan which has been producing for almost 50 years, is required to find a way to survive until end of contract in 2037 by developing the remaining hydrocarbon resources which become more and more marginal. The project development is proposed as a bundling to allow flexibility during execution phase in selecting the well candidates based on recent data acquired from previous wells drilled, hence reducing the risks. Field Development Package (FDP) 2.3 is prepared as part of PT MNO long term plan and commitment after receiving incentive from Government of Indonesia in 2021. According to the Company Guideline, a risk register is mandatory to be developed since beginning of project which covers risks identification, risks analysis, and risks evaluation. The project team is also responsible to define risks treatment to manage the risks borne by the project. This is in line with the requirement for Good Corporate Governance, where risk management is introduced since beginning of the project life-cycle. This study covers the risk assessment on the basis of selected project scope which has been validated technically. The risk assessment will determine the major risks in FDP 2.3 considering available historical data of oil price, drilling cost realization, and facility cost realization. These risks need to be monitored to ensure the FDP 2.3 will create value for the shareholder as per plan or avoid loss at the minimum. The most important risks concluded in this study is oil price lower than economic assumption, production target not achieved, and no fix gas sales contract to absorb production. The company may focus in these risks for the risk management of future project development.

Assessment of Fault Sealing in the Gabo Field, Niger Delta, Nigeria

This research assesses the sealing of the fault bounded stratigraphy of the Gabo Field, Niger Delta, Nigeria. Materials used comprises of 3D seismic volume in seg-y, ditch cuttings and well logs. The methods applied are standard fault plane evaluation techniques and they include seismic interpretation, well correlation, XRD analysis, and application of the Yielding et al., (1997) shale gouge ratio (SGR) algorithm for fault seal analysis. The tectonic framework was interpreted in terms of deformational, depositional and post-depositional structures. The order of magnitude of stress is SHmax > σv > Shmin. The juxtaposed strata relationships were analyzed by taking cross sections A-A1 and B-B1 and this showed the structural framework across the field. Cross section A-A1 showed that the depositional and post depositional structures are pinchouts (channel abandonment or switching) and shale smears respectively. The cross section B-B1, showed that the deformational structures are faults F1 and F2 – recognized as closely spaced normal faults and F3 is a syn-depoitional growth fault. The well correlation showed the vertical stratigraphy of the wells are comprised of cyclic succession of sands and shales and the shale thickness increased in intermediate sections. The X-ray diffraction (XRD) analysis of the shales showed that the predominant minerals are kaolinite, rutile, gypsum, albite, microcline and quartz. The rock property analysis showed that the net to gross ranges from 26.28 – 82.0% with an average of 73.7%. The volume of shale ranges from 18 – 73.72% with an average of 63.59%. The bulk density of the shales ranges from 2.379 – 2.692g/cc with an average of 2.46g/cc. The total porosity ranges from 0.159 – 0.317 with an average of 0.167 in the shales and 0.272 in the sand. The effective porosity range from 3.58 – 22.71 with an average of 6.028 in the shale and 20.13 in the reservoir. The drawdown mobility and temperature range is 2.2 – 4124.4mD/cP and 63.3 – 80.1oF respectively, while the average is 569mD/cP and 70.63oF respectively. The estimated pore pressure ranges from 0.4213 – 0.4762psi/ft with an average of 0.47psi/ft in the shales and 0.428 psi/ft in the sand. The fault seal analysis showed that the shale gouge ratio range from 0.2 – 0.7 and the stratigraphic juxtapositions are predominantly sand to sand, sand to shale and shale to shale. The results of this research reduces the fault seal uncertainty in the planning of oilfield development projects and enhanced pressure support for the recovery of bypassed hydrocarbons, most especially in compartmentalized reservoirs. In addition, the results of this research can be applied to similar deltaic successions around the world.

Survey of reliability of offshore oil and gas infrastructure in South Baltic conditions

The development of the hydrocarbon resources of the Kaliningrad Region shelf has been carried out systematically since the late 1980s. In the existing offshore oil and gas infrastructure of the region should be mentioned drilling platforms (C-9 and D-6), an underwater oil pipeline from the D-6 platform to the Romanovo oil collection point, the Pionersky marine regasification terminal. The experience of operating these infrastructure facilities shows that despite the low salinity of the Baltic Sea and the practical absence of ice conditions in this area, oil and gas infrastructure objects are subject to significant technical degradation. The existing offshore pipeline, which transports oil from the D-6 platform, is influenced by a complex of external factors, internal corrosion and erosion wear associated with sulphur compounds, oxygen, and the presence of abrasive particles. The study presents a factor analysis of the causes of corrosion wear of infrastructure oil and gas facilities on the shelf of the Kaliningrad region, analyses the dynamics of the processes of physical and chemical degradation of equipment surfaces. Various solutions of the reliability ensuring of these units in marine conditions are considered. The results of observations of corrosion and erosion processes in the oil and gas infrastructure of the Kaliningrad Region shelf should be taken into consideration during the development of project documentation and the selection of equipment and materials for new projects being implemented (offshore oilfield development project D-6 South and D-33).

Инвестиционная привлекательность проектов по разработке нефтяных месторождений в условиях налогового маневра. Оценка на примере Западно-Сибирского экономического района

The West Siberian economic region remains a territory with high potential of liquid hydrocarbons production, which serve as a reserve for long-term development not only for this region, but for Russia as a whole. Experts claim that Western Siberia provides 70% of Russia’s oil production and accounts for 61% of the mineral extraction tax revenues. According to forecasts of the Ministry of Energy, if oil production is not stimulated, then by 2035 the volume of oil production will significantly reduce and budget revenue will decrease by 4.1 trillion rubles. At present, in order to increase the investment attractiveness of the industry, changes in tax and customs legislation are being introduced. However, the effects of the reforms are not obvious. Employing scenario analysis, the case method and financial modeling on the basis of publicly available information, we assess the impact of changes in tax and customs legislation on the investment attractiveness of oil field development projects. The main hypothesis of the study about the positive impact of the tax maneuver on the attractiveness of projects was partially confirmed. However, in all considered scenarios the internal rate of return does not exceed 13%. This is significantly lower than the global average rate of return for oil and gas industry. This points to the need for further adjustments to the tax and customs legislation to ensure sustainable growth and development of the oil and gas industry. The model created to assess the impact of alternative tax regimes on the investment attractiveness of hydrocarbon exploration and development projects can also be used to identify potential benefits and tax consequences for both the investor and the state.

Analysis of Measures for Environmental Protection of Oil-base Drilling Fluid

With the continuous development of China ' s economy, social and industrial demand for crude oil is increasing. Therefore, how to efficiently develop oil and gas fields is the focus of oil industry practitioners. Drilling engineering is the top priority in oil and gas field development projects. Drilling fluid is an important part of oil drilling. Its main functions are cooling bit, carrying cuttings and protecting wellbore. Due to its complex composition, it will cause serious environmental pollution in the process of oil drilling. Oil-based drilling fluid is often used in special drilling operations, such as horizontal well drilling, which can effectively protect the wellbore stability and cause serious pollution to the environment. It is of great significance to strengthen the study of environmental protection measures of oil-based drilling fluid. The research on environmental protection measures of oil-based drilling fluid abroad was expounded.

Reserve Evaluation Method for New Overseas Oil and Gas Field Development Projects

Reserve Evaluation Method for New Overseas Oil and Gas Field Development Projects

On conducting additional experimental studies of the properties of reservoir fluids in the design of oil field development

The article substantiates the need to perform additional experimental studies of reservoir fluids, the results of which are used as input data for the implementation of oil field development projects. The methods of experimental research used in «Giprotyumenneftegaz» are briefly described and their main features are described.

E&P Notes (February 2021)

E&P Notes (February 2021)

Method for Determining Lowest Oil Price Limit by Developing Tight Peripheral Oil in Daqing

The outer oil field of Daqing is a low-permeability oil field, which has a large proportion of the tight oil reserves. Due to the high development costs of the tight oils, many fields are difficult to reach the standard of economic evaluation. It increases the difficulty in optimizing reserves and use of reserves. In the process of the development of the tight oil field, it is important to determine the limit of starting oil price. It is also an important basis for determining the launch of the oil field development project. The evaluation of present value method does not consider the change process of external conditions and has certain limitations. However, the introduction of investment option value method for evaluation can fully consider changes in oil prices and other external factors, and provide a more realistic assessment of the oilfield development process. In the case of low oil prices, some tight oil fields can also be used effectively, which improves the efficiency of resource utilization, increases the scale of reserves utilization, and solves the problem of optimization and evaluation of reserves.

Concept for managing constraints of an oil field development project

The article is devoted to the identification and evaluation of specific design constraints in the implementation of oil field development projects. A sequence of stages for identifying, evaluating, and managing project constraints is formed. The characteristic of the levels of manageability of project constraints is given and the actions of the manager for each level are defined. A method is proposed for determining the ranks of restrictions, taking into account the probability of occurrence of a restriction and the degree of its influence on the project result. The system of values of the point scale for assessing the levels of manageability of project restrictions is defined. Relationship established of the riskiness of the project and the level of manageability of the design constraints.

On the Valuation of Natural Resources: Real Options Analysis of Marginal Oilfield-Development Projects Under Multiple Uncertainties

Summary This paper shows the applicability and the value of real options analysis (ROA) in valuing a marginal undeveloped discovery in the UK Continental Shelf (UKCS) under multiple project uncertainties, namely geology, costs, and oil prices. Marginal fields can prove uneconomic when developed under prevailing circumstances such as technical (reservoir size, infrastructure distance and remoteness, crude-oil type) or commercial issues (oil prices, high cost of development, lack of third-party-access arrangements), among others. As such, using traditional discounted-cash-flow (DCF) methodologies such as the net present value (NPV) might not adequately value the embedded options that these uncertainties create, leading to a rejection of the investment decision. Hence, we assess if the valuation differs if valued by the traditional DCF approach compared with ROA. We develop a valuation model for the traditional DCF and real options and specifically model the flexibility in the options to delay, abandon, or expand the field anytime during the relinquishment requirement period considering these multiple uncertainties. The binomial lattice and later the Black and Scholes models are used to model the options because of the flexibility they provide in incorporating early exercise. The results indicate that the DCF values lag those of the option values for the deferral and expansion options. In contrast, the abandonment option exhibited only a marginal change with respect to the DCF value. A significant implication of this finding is that management decision making will be better off considering these embedded options in their field-development and capital-investment choices.

Computer High-precision Analysis Method for Economic Life of Oilfield Development

In the feasibility study of oilfield development projects and the management of oil reservoirs, it is necessary to calculate the economic life of oilfield development projects accurately, which is of certain guiding significance for the economic evaluation and decision of such projects. In this paper, the calculation method for the economic life of oil equipment is introduced. Examples of the specific application of the method to the equipment update decision system are illustrated. The backstage database is established to analyze the economic life of oilfield development.

NEPA Substantive Effectiveness Under a Procedural Mandate: Assessment of Oil and Gas EISs in the Mountain West

This paper empirically evaluates whether Environmental Impact Statements (EISs) for oil and natural gas field development projects lead to a significant reduction in environmental impacts. Based on our statistical analysis of projects within a four-state region, we conclude that EIS preparation does appear to produce final decisions that are substantially less impactive on the environment when compared to initially proposed projects. Impact reductions occur primarily between the Draft EIS and Final EIS, with minor reductions occurring between the Final EIS and Record of Decision. While reductions may be partially attributable to other legal requirements (such as Clean Air Act, Clean Water Act, or Endangered Species Act compliance or intervening economic and technological factors), external factors alone do not adequately explain impact reductions. We also found that the number of alternatives considered within an EIS affects the magnitude of impact reduction. EISs that consider a broader range of alternatives are more effective at reducing environmental impacts.

Risk Hedging Tools: Efficiency and Significance of their Use in the Processes of Forming Development Strategies of Russian Oil and Gas Companies

The possibilities of using hedging methods as an instrument for effective business development in the Russian oil and gas market are shown. The relevance of the study is to systematize and identify the key elements of the risk hedging mechanism for business units of oil and gas companies. The focus is on the adaptation of methods such as descriptive statistics and the ARIMA model. Information for the study was taken from open sources, including daily data from company websites and data from official websites of other organizations. The article presents a risk hedging scheme in oil and gas field development projects. The risks of the project were assessed with qualitative and quantitative indicators. This made it possible to identify the dynamics of the degree of change in the latter and evaluate the costs associated with minimizing them during the life cycle of an investment project for the development of an oil (gas) field. Recommendations are proposed to reduce the basic risks of the project. To this end, they were ranked according to their importance to the investor. Significant risks in Russia for investors in the industry are country risks, the reduction of which is a priority for attracting new investments.