Field Development Projects Research Articles

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.

Capital Budgeting and Risk Analysis for High C02 Gas Development Using DCF Model and Monte Carlo Simulation

Gas supplies in West Java are projected to have a shortage starting in 2023. Thus, PT. ABC seeks to increase gas production by re-evaluating marginal fields. One field that has the potential is X Field. However, X Field has a high C02 content (70%) which makes this development project require a significant investment to separate the C02 content. Thus, the economics of the project becomes very crucial.This paper conducts a budgeting analysis to evaluate the economics of the X Field development project. By using the discounted cash flow (DCF) method, the results of this study will assist the company in determining whether X Field is feasible to develop or not. The following approach uses Monte Carlo Simulation to consider all risks in each parameter.The results of the economic calculations show that X Field is feasible to be developed. The scenario chosen is the No Facility scenario or selling gas directly at the wellhead. The resulting NPV is 2,580 M$ with an IRR of 12.9% and a POT of 5.8 years. The Monte Carlo simulation shows that the project is risky, with a negative NPV probability of 16%. Therefore, setting the lowest gas price at 2.5 $/MMBtu is recommended.

Iterative sequential robust optimization of quantity and location of wells in field development under subsurface, operational and economic uncertainty

Determination of optimal quantity and location of wells is a crucial step in any field development project. Multiple challenges exist in the real-world projects, such as gigantic multidimensional search space and complex parameterization of the problem. To address these challenges, we present an iterative sequential optimization framework that consists of multiple stages for optimizing number and location of producers and injectors. Once the initial guesses have been established, the first optimization stage begins in order to determine the optimal number of producers and injectors. Next, a two-stage process is used to determine the best location for each well. By optimizing the number and location of wells, well type is optimized implicitly and does not need to be included in the optimization process as an individual decision variable. To consider the dependency and coupling between parameters, the entire optimization process is repeated iteratively up to a stopping point. The proposed approach is highly flexible and can be extended to include other potential decision variables of field development projects. We test the proposed methodology on UNISIM–II–D, a realistic benchmark case that represents pre-salt reservoirs in deep offshore Brazil, which are light-oil fractured carbonates with large volumes of CO2-rich associated gas. In our application, all producers and injectors are equipped with internal control valves (ICVs), all produced gas is reinjected into the reservoir, and water-alternating-gas with CO2 (WAG-CO2) is used to increase oil recovery and ensure that the produced CO2, as a harmful greenhouse gas, can be safely discarded underground. We use the iterative discrete Latin hypercube (IDLHC) optimization algorithm. To achieve a robust decision, we consider subsurface, operational and economic uncertainties by considering nine representative reservoir models and three economic scenarios. Based on the results, the proposed framework can provide an appropriate solution containing optimal quantity of wells, their locations and types in realistic cases with large search spaces and complex parameterizations.

Казус белли практической и теоретической оценок технологических процессов крупнотоннажного производства сжиженного природного газа

Almost always the results of theoretical research do not bring the desired result in practice. This is especially true if there is at least one alternative (competitive) option for applying the process. Production of the liquefied natural gas is a prime example of the need for an understanding of the choice of a single process option that will provide performance indicators with optimal energy efficiency and acceptable safety during the preliminary design stage of a project. One of the research steps may be a comparative analysis of the results of practical (operation of similar facilities) and theoretical (thermodynamic analysis) assessments of the choice of the natural gas liquefaction process at the stage of the feasibility study of the gas field development project (without considering the financial component). The task of the presented study was solved based on the indirect comparative analysis of the results of an expert evaluation of operation and theoretical results of a thermodynamic analysis of the liquefaction processes for a project in the territory of the Russian Federation. The following studies were conducted: choice of LNG technologies; expert evaluation of large-capacity projects for production of the liquefied natural gas in the climatic conditions close to the Arctic; thermodynamic analysis of the energy efficiency of the technological process of large-tonnage production of the liquefied natural gas in the territory of the Russian Federation. The result of the study is the integration of safety and efficiency for making a decision on the choice of the technological process of the natural gas liquefaction at the stage of the Safety Case of the gas field development project.

E&P Notes (July 2022)

E&P Notes (July 2022)

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.

Economic appraisal of an unconventional condensate play based on public pilot data prior to field development: Jafurah Basin case study (Saudi Arabia)

This study uses a stochastic approach to provide a holistic economic evaluation of the Jafurah field development project, the largest unconventional natural gas field in Saudi Arabia, projected to start first production in 2024. The assessment considers deterministic and probabilistic inputs based on data published in the literature, analogy with Eagle Ford reservoir parameters, and engineering-based assumptions. The uncertainty of discounted net cash flow, internal rate of return, and other target metrics for the Jafurah project is quantified (P90, P50, and P10). The results show the most likely (P50) net present value of 47.21 billion US dollars (at 10% discount rate) and a corresponding internal rate of return of 46.8%. Sensitivity analysis highlights the relative importance of the most critical probabilistic inputs (initial production rate, natural gas price, capital and operational expenses). Based on the current economic ranges and uncertainty analysis, it can be concluded that the Jafurah Field can be profitable in the long term. However, frequent reappraisals are recommended to help direct future decisions on capital expenditure programs for the drilling and completion of new wells, especially when new field performance data becomes available after the earlier wells start first production in 2024. Although hundreds of field delineation and production wells have already been drilled and completed over the past decade, major investment and time were needed to construct new regional pipelines (for gathering natural gas and liquids from each well pad), new chemical plants (for processing of the natural gas liquids), and new underground natural gas storage facilities (to buffer seasonal changes in the production supply and demand of natural gas), which is why first production is planned for 2024.

E&P Notes (May 2022)

E&P Notes (May 2022)

Economic Evaluation of Oil and Gas Projects: Justification of Engineering Solutions in the Implementation of Field Development Projects

The condition of the oil and gas sector is characterized by the complication of geological settings, and there is more competition in energy markets due to the current trend towards decarbonization. These circumstances require oil and gas companies to become more flexible and improve their project economic feasibility studies. The purpose of the research was to develop a methodological approach for the economic evaluation of oil and gas projects that includes choosing and substantiating the choice of engineering solutions that can be used to make decisions on subsequent investing. A comparative analysis of various economic evaluation methods applied to oil and gas projects included the DCF model, DPNV model with modifications, binary discounting, and reverse discounting. Taking into account the specific features of oil and gas projects, the authors provide a rationale for using a risk-free rate to calculate project outflows and a combination of reverse rates to calculate inflows. In addition, the theory of real options was applied to assess and account for geological and technical risks. These risks cause changes in the production rate when making engineering decisions. Using the proposed methodological approach, oil and gas companies will be able to evaluate in more detail and explain the influence of engineering solutions on the net present value of the project. This is the result of better consideration of geological and technical risks. The proposed approach is relevant both before project implementation and during production.

Appraisal campaign selection based on the maximum value of sequential information

Field development projects generally demand large investments which are subject to geological uncertainty, hence projects can benefit from geological information obtained from appraisal wells before large capital commitment. But “how much data is enough”? Value erosion occurs both in over-appraisal or under-appraisal of the field and the value of information rationale is ideal to determine the right amount of data. But examples from the literature are case-specific and often limited to simple assessments with a small number of alternatives and outcomes. We propose a general method to select the appraisal campaigns based on the value that spatial geological data adds to the development plan. It regards the appraisal campaign as a sequence of wells that will acquire geological data and optimally supports the next acquisition on a well-by-well basis. This approach is compelling for replication in any case because drilling wells is part of every development project. The method is demonstrated in a synthetic example with 8 candidates from which the appraisal campaign must be selected and is observed up to 65% improvement in the development project expected value. Its application provides a tailored solution different values of discount factor and information cost, which are grouped in a solution map. Results clearly show how much data should be acquired considering different circumstances and sensitivity analysis in the value function show value-adding robustness. Given the potential benefits of the appraisal selection method presented here, the modeling of spatial geological dependencies through probabilities is encouraged and future work could explore the use of subsurface flow-simulations to enhance the accuracy of the estimations by considering value coupling. • The value of sequential information (VoSI) is an effective metric to select the optimal appraisal campaign. • Information cost and the discount factor play a major role in the selection of the appraisal candidates. • Information cost has a bigger influence on the solution, especially related to the number of appraisal candidates. • Discount factor influence increases with the increase in information cost. • The division into the appraisal section and remaining section increases the information exploitation.

БЕНЧМАРК-АНАЛИЗ РИСКОВ НЕДОСТИЖЕНИЯ ПРОЕКТНЫХ ПАРАМЕТРОВ ТЕХНИКО-ЭКОНОМИЧЕСКОГО ОБОСНОВАНИЯ ОТРАБОТКИ МЕСТОРОЖДЕНИЯ

The mine development project is a set of works, which, due to the uniqueness of mining and geological cond卜 tions, territorial location, climatic factors, lack of the necessary infrastructure, will be subject to a high degree of project risk. The aim of the work is to increase the implementation efficiency of the field development project based on a comparative analysis of the main technical and economic indicators with world industry leaders. Ma- teria/s and methods. Based on the model of the mineral resources of the deposit and the comparative analysis carried out with a reference base with more than forty leading world deposits (benchmarking), a strategic anal-ysis of the main technical, technological, organizational and economic parameters of open pit development has been carried out. The risk analysis, the input parameters used in the preliminary feasibility study of the project are adjusted and updated. The choice of the limiting open pit shell has been carried out, the problem of choosing the mining method and parameters of the equipment used has been solved, and the analysis of the optimal height of the open pit bench and the stages of development of technological blocks of the field have been carried out. Results. The obtained values of the main technical and economic indicators have formed the basis for the formation of a mining plan, as well as an assessment of operating and capital costs, taking into account risk factors. The following most significant risks are identified: availability of staff with relevant experience and competencies required to implement the mining plan; oxidation of long-term storage ore warehouses, which leads to a decrease in mineral extraction rates; high diesel and electricity costs. Conclusions. Based on the identified risk factors, capital and operating costs have been determined and adjusted for the level of energy consumption, the cost of drilling and blasting operations, control of the content of the useful component, loading, maintenance costs, labor costs and general costs

Evaluation of Oil and Gas Economy using Economics Profit Indicators and Prototype Macro VBA Excel

The oil and gas sector is an important factor in sustainable development, so it is considered necessary to make serious changes in conducting economic analysis on the oil and gas business. Oil and gas industry activities consist of upstream activities, and downstream activities. Activities in these upstream and downstream operations have high risk, high costs and high technology, so the company continuously tries to reduce the importance of the adverse impact of these risks on the work environment and people. Thus, evaluating the factors that affect sustainable production in this sector becomes a necessity. In this research will be evaluated the economy of the oil and gas field using methods of economic indicators, among others; NPV, POT, ROR, where these factors are estimated in order to be able to estimate the prospects of the oil and gas field so that the decision that the field development project can be implemented or cannot be taken immediately. Implementation of oil and gas field economic evaluation in this study using Macro VBA Excel. From several methods of economic analysis obtained that the results of this study show high precision compared to other methods, in addition to the way of evaluation using the above economic indicators is very popular.

Workflow for Probabilistic Resource Estimation: Jafurah Basin Case Study (Saudi Arabia)

This study provides a workflow and preliminary estimations of the estimated ultimate recovery (EUR) volumes for natural gas and condensate liquids in the Tuwaiq Mountain Formation, the principal target in the Jafurah Field development project in Saudi Arabia. The strategic need for the field development is reviewed and the field characteristics are outlined based on public data sources complemented with data from analogous reservoirs. The target zone in the Jafurah Basin is a carbonaceous shale, being developed with up to 10,000-ft-long multistage-fractured laterals with 30 ft perforation cluster spacing and an assumed typical 1250 ft well spacing. The field will come on stream in 2024, when the gas-gathering pipeline system, natural gas processing plant, and underground gas storage facilities will all be in place. The range of uncertainties in the key reservoir parameters is taken into account to estimate preliminary EUR volumes (P90, P50, and P10) for both gas and condensates. Based on the present and prior EUR estimations, it can be concluded that the Jafurah Basin comprises one of the largest unconventional field development projects outside of North America.

Optimization approach for Arctic field development design using subsea production systems

Russian experience in the design of trunk pipelines and Arctic studies have been used to develop an efficient model and method for Arctic field development design using the subsea production system (SPS). Compared to 2D models used in the past, the new design technique offers an opportunity to make 3D models and can be used for optimization of offshore field development projects. The proposed optimization model is based on the Bellman - Ford algorithm developed for 3D networks. This approach has been used for the first time to capture key features and specific subsea production system design processes. The algorithm and block diagrams developed for the proposed SPS design method is universal. This method can be used to address tasks of a more general nature. Optimization of the particular case between a single start point (well location) and single end point (SPS facility) is implemented as a separate software package, but the scope of applications is not limited by such cases and may be extended even further. It can also be very efficient for Arctic subsea field development.

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

Formation of the Organizational Structure of Managing a Large Project of Oil Field Development

The article analyzes the organizational structure of the project management development with regard to the field of traditional oil reserves, functional responsibilities and areas of responsibility of its participants, as well as the mechanisms of their interaction during the implementation of work to form the organizational structure of managing a large and unique project – the development of high-viscosity oil deposits. It has been revealed that in modern business conditions the implementation of projects for the development and recovery of high-viscosity oil fields based on the traditional organizational structure of management is not effective enough. The main reasons that impede the successful implementation of projects for the development of new deposits based on the traditional organizational structure of management are identified. A new organizational structure for managing a field development project is proposed, which includes a single center of responsibility for the field development project. By the example of the Ashalchinskoye field, the economic effect of using the formed organizational structure for managing the project for developing the field in the form of a possible additional annual oil production was calculated.

Experimental Study About Water Saturation Influence on Changes in Reservoirs Petrophysical Properties

Experimental determination of the physical properties of rocks under conditions simulating in situ reservoir conditions is of great importance both for the calculation of reserves and for the interpretation of well logging data. In addition, it is also important for the preparation of hydrocarbon field development projects. The study of the processes of changes in the petrophysical properties of the reservoir under controlled conditions allows not only to determine their reliability but also to evaluate the dynamics of these changes depending on the temperature and pressure conditions of the reservoir and the water saturation of the rocks. In this work, an evaluation of the dependence of the physical properties of hydrocarbon reservoirs on their water saturation (Sw) was carried out. Residual water saturation (Swr) was created in the rocks and the properties of these rocks were compared at the states of partial (25 %) and complete water saturation (100 %). The changes in petrophysical parameters of partially water saturated rocks during the increase in effective pressure were studied and estimates of these changes were obtained. The results showed that when the effective pressure is increased, the Swr increases by an average of 6 % compared to atmospheric conditions. This is accompanied by an increase in the velocity of longitudinal (by 51.9 % on average) and lateral waves (by 37.1 % on average). As residual water saturation increases, effective permeability decreases for both standard and reservoir conditions, with, gas permeability decreasing for both dry samples (by 23 % on average) and samples with residual water saturation (effective permeability decreases by 27 % on average). HIGHLIGHTS Changes in physical properties of hydrocarbon reservoirs by determining physical properties (permeability, porosity, elastic, electrical, deformation strength) under the standard conditions and in physical modelling of reservoir conditions and processes Assessment of the effectiveness of water saturation on the physical properties of the reservoir Comparisons between the petrophysical properties of reservoir core samples in which the pore space is fully saturated with the reservoir fluid model and samples with residual water saturation Experimental determination of the physical properties of rocks under conditions simulating in situ reservoir conditions Estimation of the changes in petrophysical parameters of partial water-saturated rocks during the increase in effective formation pressure GRAPHICAL ABSTRACT

Successful Fishbone Stimulation Completion for an Onshore Oil Field, United Arab Emirates

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 203086, “First Successful Fishbone Stimulation Completion in Onshore Oil Field in the United Arab Emirates,” by Fernando Quintero, Noor Talib, and Alvaro Jimenez, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. The complete paper describes the operator’s first implementation of fishbone stimulation technology. A multidisciplinary team analyzed the operational procedures, conducted risk assessments and logistical studies, and established contingency plans, technical requirements, and technical limitations. The deployment of the equipment and the production results were a success, overcoming hazard risks and uncertainties and closing gaps from previous, partially effective applications. According to the authors, fishbone stimulation technology will help increase productivity in a well too risky to be hydraulically fractured and beyond the reach of coiled tubing. Background As the industry seeks dynamic changes and novel ideas to increase the productivity of tight, thin reservoirs, fisbone stimulation represents a lower-risk and -cost solution to ensure deep connectivity with the reservoir in situations in which traditional conventional stimulation practices have reached their potential boundaries without achieving crude recovery objectives. The project described in the complete paper is part of a series of field-development projects in United Arab Emirates onshore fields to exceed expectations of the committed production targets. This trial has taken the form of a pilot test for implementing fishbone stimulation for a short duration in other onshore fields. The new approach has already enhanced production up to three times and has provided wellhead pressure support. While this marks a successful beginning, more field trials will be needed to implement wider use of this technology. Fishbone completion stimulation technology is based on the use of subs that are installed in uncemented liner in which each sub features four small-diameter, high-strength tubes called needles (Fig. 1) that can be extended up to 40 ft in length by bullheading acid (Fig. 2). The objective of the technology is to increase well productivity and injectivity by the needles by connecting natural fractures and vertical layers and increasing reservoir contact and effective well-bore radius. To address the deployment challenge, a risk assessment was under taken with the active participation of a multidisciplinary team, including members from the operator (drilling and asset team) and the service company, to ensure that all required precaution inputs were considered. The risk assessment was conducted by identifying the situations that could threaten the deployment and full extension of the needle, a critical aspect of the job. The complete paper describes primary factors such as the following: - Sub-assembly preparation - Running liner to total depth and setting liner hanger - Mixing and handling hydrochloric acid (HCl) - Pumping the acid job - Fluid losses after the acid job - Cleanup runs with fishbasket cutting assembly

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.