Optimisation of the wells placement in gas reservoirs using SIMPLEX method

In response to Governor Brown’s January 2016 state of emergency proclamation regarding the Aliso Canyon gas leak, SB 826 (Leno, 2016) requested that the California Council on Science and Technology (CCST) provide the State with up-to-date information on all currently operating underground natural gas storage fields in California. CCST was instructed to provide an independent technical assessment answering three key questions about: The risks California’s underground gas storage facilities pose to health, safety, environment, and infrastructure; Whether California needs underground gas storage to provide for energy reliability through 2020; and How implementation of California’s climate policies changes the future need for underground gas storage. From a statewide field of leading energy researchers, CCST selected Jens T. Birkholzer, PhD, and Jane C.S. Long, PhD, to serve as co-chairs of the 12-member CCST Report Steering Committee – which supervised 21 Report Authors with expertise spanning hydrogeology and reservoir engineering, risk assessment, public and occupational health, greenhouse gas (GHG) emissions, and energy analysis and economics. Each report chapter was subject to a peer review process by independent experts, while another independent expert served as Report Monitor to oversee the process, ensuring that peer review comments were sufficiently addressed in the final report. An additional Oversight Committee reviewed the entire process, including conflict-of-interest declarations. The report’s findings and conclusions are based on a review of published literature and official and voluntary databases, which the Report Authors compiled between January through September 2017, and delivered to the California Public Utilities Commission in January 2018. Key findings and conclusions include: Safety: The risks associated with underground storage (UGS) facilities can be managed, and, with appropriate regulation and safety management, may become comparable to risks in other types of energy facilities found acceptable in California, such as oil refineries and natural gas power plants. At each UGS facility, the State should ensure timely and thorough implementation of the new regulations coming into force in 2018 set by the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR). Those regulations emphasize new and safer well completions, risk and safety management plans, and requirements for well integrity testing and monitoring. The report recommends that the State go further and require more quantitative risk assessment activities, including consideration of human and organizational factors affecting risk. The State should also implement an independent and mandatory review program to evaluate the effectiveness of these new regulations and the rigor of their application in practice, with opportunity for public comment and public dissemination of the review results. Facility-by-Facility Evaluation: Any industrial operation involves some risk to health, safety, and environment. This report assessed various risk-related characteristics across UGS facilities in California, and found a small list of facilities had relatively higher potential risk compared to others. Reliability of Natural Gas Supply: California’s energy system currently requires natural gas and UGS facilities to run reliably, primarily because many residential and commercial buildings in California rely on natural gas for heating during the winter, and because natural gas provides electricity when solar and wind power are not available. The peak demand for natural gas during the winter currently exceeds the ability of pipelines to bring natural gas into the State of California, so natural gas must be stored during periods of low demand in order to have it available to meet peak demand. Near-Term Alternatives to UGS: Closing any or all UGS facilities in the near term would involve replacing UGS facilities with new pipelines or natural gas storage capacity, and require very large investments. Such new natural-gas-related infrastructure would bring its own risks and would further obligate the State to the use of natural gas for decades. The risks, costs, and benefits associated with alternatives to UGS storage should be evaluated accordingly. Long-Term Need for Underground Gas Storage: California’s climate policies in future decades could still necessitate the continued use of natural gas. Also, energy systems that meet the climate goals may require underground storage of natural gas, biogas, or hydrogen, as well as sequestration of carbon dioxide. The State should develop a more complete and integrated plan to understand how the role of natural gas might evolve; assess possible energy portfolios that both meet GHG emission constraints and achieve energy reliability; and consider the potential need for UGS facilities in the future.

Nigeria is the 2nd biggest natural gas producer in Africa, with much of it exported as LNG, some re-injected while a small fraction serves the domestic market. The volume supplied to the domestic market plays an outsized role in the energy mix and economy of Nigeria with over 90% supplied to thermal power plants and industrial clusters. As huge upstream gas projects continue to take Final Investment Decision, pipeline takeaway capacity grows and demand increases, the dependence on natural gas and preponderance in the energy mix will likely persist. Natural gas is the present and future of Nigeria's energy needs. The domestic gas industry is evolving but has been fraught with challenges. Oil and gas infrastructure are often disrupted and production shut-in, mostly triggered by infrastructure unavailablity, environmental concerns and prioritisation of hydro power generation during River Niger's white and black floods, all of which come at a cost to upstream producers. Gas producers are often compelled to curtail production of gas plants (associated and non-associated) to avoid environmental disasters and prohibitive gas flare penalties. Can underground gas storage (UGS) be an opportunity for gas producers to guarantee continued operations during disruptions and provide buffer for national strategic benefits? This paper seeks to explore the potential technical and economic dynamics of underground natural gas storage in Nigeria in the context of extant technical regulations, seasonal demand variations, gas flare penalties and local operating environment. The paper presents types of underground storages and recommends the most suitable, considers options for optimal location of UGS in Nigeria and undertakes an economic evaluation of a UGS project. The findings are further presented alongside the critical technical, regulatory and fiscal factors that may facilitate future investments and growth of underground gas storage in Nigeria.

This paper presents results of an underground gas storage modeling study using the reservoir and fluid properties of the Northern Marmara gas field, a recently developed field in the Thrace region of Turkey. It has an area of 3.6 km2 with nearly 3 billion sm3 of GIIP. The reservoir model used in this study is based on the theoretical as well as the empirical deliverability equations. The deliverability equations reflect the production and injection performances of the wells with given completion characteristics. Our approach is based on maximizing working gas volume for a particular configuration of reservoir, well and surface facilities. The importance of the type of well completion was emphasized in this paper because this is the most likely place for operating problems to occur. The deliverability performance strongly affects the design factors such as the working gas volume and the number of wells operated. Results indicate the performance dependence on wellbore damage and hence the importance of cleanup of wells. The effects of the mechanical skin factor on the working gas capacity with different number of horizontal wells as well as vertical ones were studied. Results show that the working gas capacity decreases while the mechanical skin factor increases. This behavior becomes especially more dramatic as the horizontal well length decreases. The increasing number of wells increases the working gas capacity as expected. These results are discussed in detail through application to N. Marmara gas reservoir data. The underground gas storage modelling approach followed in this study is shown to be an effective way to forecast the production / injection performance and to estimate the important design parameters when converting a depleted gas reservoir to a gas storage reservoir. Our approach yields the better understanding of the effect of the wellbore conditions on the performance of the underground gas storage reservoirs as well.

In this study, we present an integrated digital underground gas storage (UGS) solution in response to China's dynamic energy requirements. The solution leverages the inherent functionalities of an industry-standard high-resolution reservoir simulator to run a set of automated workflows that utilize a coupled reservoir-surface network model for alternating production and injection cycles of the UGS. The output from the workflows is displayed on interactive dashboards for user action. This innovative solution sets a precedent for similar UGS projects, promoting safe and cost-efficient UGS operations. To capture the UGS performance factors, production and injection integrated asset models with reservoir model, and steady-state wellbore and surface network model coupled have been introduced. When compared with standalone simulation and analysis, the coupled model becomes more realistic and shows new insights, helping decision makers improve planning when managing UGS cyclic production and injection. Using the UGS reservoir-well-network integrated model as an engine, tailored workflows have been developed, providing useful inputs for UGS management. The online autotracking workflow launches everyday regularly, to update the integrated model with the field data and perform the UGS evaluation, which includes the performance so far of the current cycle, followed by forecasting of the overall capability. The operational scheduling workflow enables a streamlined and interactive approach for on-demand what-if scenario analysis by varying system constraints to assess UGS performance, enabling faster and efficient responses to market requirements. This solution transforms and shifts traditional standalone analysis and field management methods into an integrated, model-based approach, delivering instant insights through interactive dashboards. When the integrated concept is applied to UGS operations and planning, operational strategies become more realistic and reasonable, providing detailed insights into the number of wells required to meet specific production demands, which wells are they, and the open/shut sequence responses to changes. Automation drastically reduces the response analysis time from weeks to only half an hour, significantly accelerating decision-making processes. This integration mitigates flow assurance issues, preventing costly well shutdowns and effectively managing pipeline blockages. With an 82% increase in automation, a 50% boost in operational efficiency, and a 30% reduction in costs and production risks, stakeholders can swiftly respond and enhance organizational effectiveness. This project has also led to the commencement of three similar ventures in the region, providing a reusable solution for UGS systems. This integrated solution provides tailored workflows for UGS systems, seamlessly connecting reservoir, wellbore, surface pipeline, and export station data and facilitating cross-domain information exchanges within a single collaborative environment. The solution leverages advanced domain technologies and web application programming interfaces (APIs) for visualizing workflow outcomes and enabling user interactions. This marks a significant shift from the traditional reliance on user experience to empowering users with streamlined processes and data-driven decision-making.

The productivity evaluation of gas reservoirs is used to determine the optimal number of well pattern, which is an important part of the preparation of gas reservoir development plan. Using integral transformation and asymptotic analyses to solve the pseudo steady-state flow model in closed rectangular gas reservoir of constant thickness, analytic solution of pressure distribution of eccentric well can be obtained. This paper presents mathematical model of multiple wells producing from a closed gas reservoir by applying the principle of pressure superposition. The pseudo steady-state dimensionless production index is introduced to solve the multiple well mathematical models under the constant pressure, and the number of production wells and cumulative production in different production interval are obtained. The results of the calculation shows that the curve of the cumulative production and economic benefits have a maximum value when the producing time, gas price, and drilling costs are given, so it can determine the optimal number of wells and provide the basis for making gas reservoir development plan.

Evaluation of underground gas storage capacity in the depleted gas reservoir with water evaporation and salt precipitation

Main objective of this study is dealing with a real case study of an Iranian gas condensate reservoir for the purpose of underground gas storage. Doing such a study in this reservoir will aid developing this technology and also demonstrates new concept of underground gas storage in partially depleted gas reservoirs. After gathering some data about the reservoir and preparing a geological model for the field, a simulation plan considered for this field. Static model converted to a dynamic one by assigning reservoir fluid data. Finally, compositional model of the reservoir prepared and verified to be accurate through a history matching process. After being sure about accuracy of the model and validating it, different scenarios for underground gas storage developed. Depletion and gas storage scenarios made for the field and results obtained. Gas storage in partially depleted gas reservoir considered in scenarios for developing this field too. After comparing different scenarios some practical results achieved and best scenario for developing this field chosen. Introduction An underground gas storage system can be defined as a combination of a constant supply with a variable demand for economic advantages[1]. In other words, it helps to combine low-demand summer season and high-demand winter season. The whole process is injecting natural gas or rarely other gases into subsurface reservoirs in the periods that demands fall bellow the gas supply. When demands exceed the supply, the gas will be withdrawn from the reservoir. Fluctuating demands due to temperature and climate make it an economic process that is necessary in many cases for efficient use of the pipelines. It also helps to have an effective delivery during peak demand seasons. This process can also help producing oil or condensate and can be considered as an IOR method too. By increasing demand of gas in many areas of the world, developing storage plans and effective use of existing storage sources is a priority for engineering and economic advantages. Figure 1 illustrates natural gas supply and demand relation and clarifies importance of having some gas stored in low demand periods in order to use in high demand periods. Figure 1- Natural gas supply and demand. (Source from [2]) (Available in full paper) Depleted gas reservoirs called to be the best choice of underground gas storage and almost all early projects were developed in depleted gas reservoirs. There are of course other types of underground gas storage that are storing gas in aquifers and in caverns and salt structures. Peak load natural gas consumption has become a problem in big cities in Iran, especially in Capital. Underground gas storage technology seems to be a helpful key to overcome this trouble. Reservoir Summary A gas condensate reservoir is chosen for the purpose of underground gas storage that is located in central Iran. This field discovered in 1955 and its production started in 1959. It has a structure that is a northwest-southeast trending anticline approximately 25 kilometers long and about five kilometers wide. The structure is investigated by surface and seismic surveys and eight wells drilled on the field.

The objective of this article is the analysys of methods for preventing and eliminating hydrates formations, classifying them and choosing the best ones for use in underground gas storage facilities. Comprehensive measures for the stable operation of gas storage facilities in the presence of conditions for the occurrence of hydrates formations were developed. Zones, being potentially prone to the hydrates formation during the gas storage facilities operation were identified. The operational parameters of gas storage wells during gas withdrawal are analyzed. The identified wells were operated under difficult conditions due to the deposition of hydrates on the wellheads, in flowlines and process equipment of gas storage facilities. The places of the highest hydrates accumulation on underground gas storages were determined: from the bottomhole of wells to the gas purification unit of the gas gathering station. Hydrate-prone zones were identified by computational fluid dynamic (CFD) modeling at the location of regulating choke installations in underground gas storage facilities. The zones of the greatest hydrates accumulation on underground gas storages were determined: from the bottomhole of wells to the gas purification unit of the gas gathering station. The analysis of the methods used in gas storage facilities of Ukraine to prevent and eliminate hydrates formation was out. A set of measures was proposed to prevent the hydrates formation in storage facilities to ensure their stable operation. Based on the Euler approach (Mixture model) by CFD modeling, zones prone to hydrates formation were determined at the installation site of regulating chokes in underground gas storages. The influence of the degree of fittings opening on the location of potential zones prone to hydrates formation was estimated. The gas-dynamic processes in the internal cavity of the gas pipeline at the installation site of the control fittings were studied and their influence on the distribution of bulk particles of the gaseous and liquid phases was established. Based on the studies performed, it was recommended to change periodically the mode of well operation for a certain time by opening or closing the regulating choke under favorable conditions for the formation of hydrates, especially at low ambient temperatures. The obtained results of experimental studies and calculations showed that in order to solve the problem of hydrates formation at gas storage facilities, it is advisable to use diverse measures through the introduction of modern intelligent systems for monitoring and controlling the technological process. Further refinement of the algorithm of the proposed monitoring and control system with its approbation in production was provided. The results of the experimental studies and CFD modeling carried out allowed providing a more reasonable approach to the application of various available methods and measures to prevent hydrates formation in underground gas storage facilities. This approach made it possible to develop new effective ways and measures to prevent such complication. Based on the conducted experimental studies and modeling, the major zones prone to hydrates formation in underground gas storages were determined. The developed measures will allow timely detection and prevention of hydrates formation at gas storage facilities are original.

Chinese Petroleum Corporation started the import of Liquified Natural Gas (LNG) from Indonesia in 1990 and utilized a depleted gas reservoir, Tiehchenshan Gas Field, to store the surplus LNG. With a compositional reservoir simulator, this paper investigated the feasibility of using CO2 as a tracer for monitoring the flow path of injected LNG. The CO2 content in the Tiehchenshan gas and Indonesia LNG is around 2 mole % and 0 mole %, respectively. The simulation results indicated that monitoring the CO2 concentration change at the producing wells would help understand the flow path of the injected gas and the reservoir description for Tiehchenshan Gas Field. Currently, compositional simulators seldom take the radioactive decay into account. This paper successfully developed a simple method which would allows the users of compositional simulators to design a test using a radioactive tracer. The simulation results showed that the mechanism of radioactive decay must be taken into account during the design and analysis of radioactive tracer tests for underground gas storage operations.

An overview of underground energy storage in porous media and development in China

Application of DOE and metaheuristic bat algorithm for well placement and individual well controls optimization

Summary The operation of underground gas storages may be accompanied by deterioration of the technical condition of wells. This is due primarily to the variables of temperature and pressure loads of the element in the wellbore during injection and extraction of gas, which most from the earth’s surface and to a depth of 500–700 m. Under the influence of these factors disrupted the adhesion of cement to casing and formation, occur the leakage of columns, gas leakage from the wellbore, the accumulation of gas behind the columns and headers, behind-the-casing flows from the storage reservoir into the overlying sediments. All this results in considerable industrial gas accumulations, the complication safe operation of UGS and disturbance of the ecological situation in the area. Therefore, the development of the technology search wells — sources of technogenesis, elimination of leaks and cross-flows of gas in them is an urgent task for underground gas storage. The work deals with the identification of cross-flows in the wells of underground gas storages. We consider mathematical models and algorithms for identifying cross-flows according to the thermometer wells. Examples of the interpretation and processing of data, previous studies of wells, underground gas storage.

In oil field development, the optimal location for a new well depends on how it is to be operated. Thus, it is generally suboptimal to treat the well location and well control optimization problems separately. Rather, they should be considered simultaneously as a joint problem. In this work, we present noninvasive, derivative-free, easily parallelizable procedures to solve this joint optimization problem. Specifically, we consider Particle Swarm Optimization (PSO), a global stochastic search algorithm; Mesh Adaptive Direct Search (MADS), a local search procedure; and a hybrid PSO–MADS technique that combines the advantages of both methods. Nonlinear constraints are handled through use of filter-based treatments that seek to minimize both the objective function and constraint violation. We also introduce a formulation to determine the optimal number of wells, in addition to their locations and controls, by associating a binary variable (drill/do not drill) with each well. Example cases of varying complexity, which include bound constraints, nonlinear constraints, and the determination of the number of wells, are presented. The PSO–MADS hybrid procedure is shown to consistently outperform both stand-alone PSO and MADS when solving the joint problem. The joint approach is also observed to provide superior performance relative to a sequential procedure.

<p>The Netherlands is seeking ways to integrate large amounts of renewable energy production capacity (wind/solar) into its energy system, in order to reduce CO<sub>2</sub> emissions and decrease dependency on future energy imports. Currently the Netherlands uses underground gas storage (UGS) to provide flexibility to its natural gas system, and secure supply during the winter season. However, hydrogen is considered to be a potential candidate to substitute natural gas, because it is a versatile energy carrier that can be produced from renewable electricity and be used as a CO<sub>2</sub>-neutral fuel and feedstock. It can also be stored in large amounts underground. Storage of compressed hydrogen in salt caverns is a proven technology, with single-cavern storage capacities in the range of 10-100 million m<sup>3</sup>. Yet some studies on the future Dutch energy system suggest much larger volumes of hydrogen storage may be required (1 to 50 billion m<sup>3</sup>). This large storage capacity can only be practically achieved in depleted natural gas fields. UHS in gas fields is not yet a proven technology. Only some pilot projects have successfully injected small amounts of hydrogen in some available underground reservoirs. In order to make possible future development of UHS, screening methodologies are needed for the readily identification and characterization of potential underground candidates. In this study, we develop a methodology that allows assessing UHS performances of large portfolios of underground reservoirs. As a case study we use the entire portfolio of natural gas fields in the Netherlands, including three UGSs.</p><p>In a first stage of our study, we conducted a nodal analysis of the Inflow Performance Relationship (IPR) and the vertical flow performance (outflow) curves, in order to obtain a first order estimate of the potential UHS performance for each field (e.g. rates of injection/withdrawal, working/cushion gas volumes and ranges of working pressures). Results show that withdrawal performances of wells in an UHS can be 2-3 times higher than those in an UGS. High bottom-hole drawdowns and erosional velocities in the production tubing may however significantly restrict the potential flow of hydrogen. Furthermore, the working gas volume of an UHS may contain up to four times less energy than that of an UGS, if operated at the same ranges of working pressures. Secondly, we used Eclipse 300, and the geological Petrel model of some of the best candidates, to conduct a more detail analysis of their potential UHS performances and the controlling factors. For that we ran consecutive injection/withdrawal cycles at different timescales (daily-weekly-monthly), and distinct working pressure ranges and types of cushion gas (e.g. nitrogen/hydrogen). Results allow to determine the efficiency of the different operational strategies and the number of wells required to match the expected future demands of hydrogen in the Netherlands. They also show the degree of hydrogen mixing with the residual and cushion gas during each cycle. Therefore our analytical/numerical modelling approach provides a good methodology to quantify and rank potential UHS reservoir candidates, and a means to classify the potential storage capacity of the entire portfolio.</p>

Determination of optimal well locations is a challenging task because engineering and geologic variables affecting reservoir performance are uncertain and they are often correlated in a nonlinear fashion. This study presents an approach where a hybrid optimization technique based on genetic algorithm, with polytope algorithm as the helper method, was used in determining optimal well locations. The Hybrid Genetic Algorithm (HGA) has been shown to work on synthetic and field examples alike. The HGA was used to optimize both horizontal and vertical wells for both a gas injection and water injection projects with net present value (NPV) maximization as the objective. Comparison of results was made between locations proposed by the HGA and those selected by engineering judgment. Results showed that horizontal wells performed better than vertical wells from the recovery standpoint for the synthetic reservoir. For a real reservoir, however, horizontal wells performed only marginally better than the vertical wells owing to low-kv/kh ratio. We also observed that optimal well locations are a strong function of the anticipated project life. A method of integrating the HGA with Experimental Design (ED) was also investigated. For this purpose, a synthetic reservoir was used and exhaustive runs were made with increasing well count. In this particular case study, we observed that the uncertainties in the variables affecting recovery did not affect the optimal number of wells required to develop this reservoir. Thus, forehand knowledge of the well count eliminates the need for the inclusion of this process variable in the ED matrix.