The use of less expensive inert gas to substitute all or part of the base gas requirements in underground natural gas storage fields is a promising technology that has been successfully field tested in France. This paper discusses geological, reservoir, and operational factors that need to be considered in selecting an underground storage field for inert gas use. A storage field in the U.S. has been selected to illustrate detailed data collection and analysis that will lead to formulation of a plan to inject inert gas and predict long term field performance using reservoir models. High base gas fraction, the presence of closed structure or an isolated area away from the injection/withdrawal wells, absence of large scale heterogeneity, and availability of adequate data for reservoir modeling are favorable features that would make a field an attractive candidate for inert gas use. The degree to which natural and inert gases will mix during the storage field operations can be predicted with the help of reservoir simulators now available. Introduction In an underground storage field, a large part (40 – 70%) of total gas stored is used as cushion to provide a desired deliverability, particularly at the end of the withdrawal season. When a storage field is abandoned, a significant portion of the base gas is not economically recoverable. Base gas costs are a major cost item for new storage fields. This is particularly true for aquifer storage fields, which tend to have a higher-fraction of base gas (about 60% in 1983) and at the same time lose more gas at abandonment than depleted fields. In new storage fields where cushion (base) gas must be supplied at present prices, substantial reduction in cost can be achieved by using less expensive inert gas instead of natural gas as base gas. The use of inert gas to replace all or a part of existing storage field base gas requirements may also be feasible when viewed with the following perspective:The replaced natural gas will be available for use by consumer.There may be a possibility of sharing the differential cost (cost difference between the current selling price of the replaced gas and initial acquisition price) between consumer and storage company.Replacement of natural gas by inert gas will result in saving of valuable natural -gas which would have been lost at abandonment. A number of investigators, have examined the feasibility of an inert gas cushion in gas storage. The key technical issue identified by these studies is mixing 1 between inert base and working gases. One study expressed concern that mixing between inert and pipeline quality gases may reach such proportion that separation would be required to yield pipeline quality working gas. This would erode some advantages gained by less expensive inert base gas. Application of inert gas in fields with natural fractures, large scale heterogeneity and irregularly placed injection/withdrawal wells (scattered all across the reservoir) would undoubtedly lead to quick production of inert gas. In view of this, the concerns expressed by earlier investigators may be genuine to some extent. However, careful planning to avoid quick breakthrough of inert gas and utilize those criteria that can keep the heavier inert gas away from the location of active storage wells would reduce the chances of mixing inert gas with natural gas. P. 353^
In gas storage wells, many different types of formation damage can occur that dramatically curtail injection and withdrawal rates. Some of these damage mechanisms are similar to producing wells (mud/cement damage during drilling, completion problems, etc.); however, some types of damage are more specific to gas injection and storage (bacterial growth, contaminants, etc.). All these different damage mechanisms require different stimulation treatment methods and fluids to increase injectivity and deliverability. However, diagnosing the correct type of formation damage is not a simple task. The process requires gathering specific types of data and interpreting the results. Correct diagnosis of the actual damage mechanism(s) and design of the appropriate treatment requires expertise and experience. Over the years, numerous studies have been performed on formation damage, and a vast amount of experience has been obtained on the design of stimulation methods and fluids to remove damage. However, this knowledge and experience is not always available or accessible to engineers dealing with stimulation design, especially with the unique types of problems associated with gas storage reservoirs. This paper describes a comprehensive computer model designed for gas storage wells to help engineers diagnose formation damage and select the best stimulation treatment. The model combines domain knowledge bases with the best available expertise using fuzzy logic and expert system technologies. After diagnosing the most likely formation damage mechanism(s), based upon input data, the program will select the best treatment method and recommend treatment fluids and additives for the stimulation. Introduction The gas storage industry uses more than 400 reservoirs and 15,000 wells to store and withdraw gas, making it a significant contributor to gas supply in the United States. It is typically observed that many gas storage wells show a loss of deliverability each year caused by a variety of damage mechanisms. In fact, the American Gas Association estimates a deliverability loss of approximately 3 Bscf/D each year. Tens of millions of dollars are spent each year to recover or replace lost deliverability, including both the drilling of new wells and the stimulation/remediation of existing wells. Recently, the Gas Research Institute (GRI), working with gas storage operators, conducted a research project to address the damage mechanisms occurring in storage wells.1 In this project, multiple wells were evaluated in more than 10 gas storage fields. Numerous downhole tests were performed in those wells, including well tests to quantify skin damage. Downhole samples of fluids, wellbore solids, and core were also obtained to characterize the damage mechanisms. As a result of this study, damage was identified in many of the study wells. The types of damage were primarily:bacteriainorganic precipitates, including iron compounds, salts, calcium carbonate, and barium sulfatehydrocarbons, organic residues and production chemicalsparticulate plugging Several other damage mechanisms were identified, including completion/stimulation fluid effects, relative permeability effects, sanding, and mechanical obstructions. GRI initiated this project to assist gas storage operators in diagnosing these potential damage mechanisms and designing optimal treatments to remove the damage. The goal of the project (and the subject of this paper) was to develop an expert system that could capture the knowledge and experience from previous studies, and the industry in general, so that these processes could be automated. Technical Approach On the basis of our experience with developing a comprehensive expert system,3–6 we outlined the following technical approach for the project.
This paper presents the results of a 2-year, GRI/DOE-funded project undertaken to determine the damage mechanisms that affect the 15,000+ U.S. gas-storage wells. The paper identifies damage mechanisms based on the evaluation and field testing of 32 wells from 12 reservoirs. The 12 reservoirs were selected as a representative cross section based on a statistical analysis of existing storage database information. Downhole diagnostic field results presented include (1) well test analysis to determine quantitatively if damage existed, (2) downhole video to observe the wellbore and formation areas, (3) physical sampling of downhole liquids and solids, and (4) rotary sidewall core samples of the wellbore face as a "biopsy" of the storage formation. This paper incorporates (1) guidelines for the candidate well selection processes and various strategies/test procedures that may be used to determine damage based on the reservoir and available information, (2) a systematic approach for field and laboratory testing to identify causes of deliverability reduction, and (3) general conclusions for the overall storage population based on the representative candidates. Introduction In the more than 400 U.S. storage reservoirs that represent approximately 15,000 individual wells, most gas-storage operators experience an average loss in deliverability of approximately 5% in 1 year. This decline rate, based on reported American Gas Association (A.G.A.) deliverability capacity, translates to approximately 3 Bcf/D each year for the entire industry. The Mauer Engineering study estimates the spending to recover or replace deliverability and maintain the current rate of deliverability at tens of millions of dollars per year. These expenditures include both drilling and stimulation/remediation. However, drilling is the more costly method of retaining or recovering this loss, and as the demand for storage increases, the need to improve and maintain deliverability in existing wells also increases. Two problems exist regarding the cost of recovery and replacement of deliverability. First, a significant portion of this money is expended without a clear understanding of the damage being addressed. Second, while operators may understand the various mechanisms of damage that could account for the loss, they have no diagnostic approach available that will help them determine which mechanism is responsible for the loss in a specific circumstance. Therefore, the choice and design of remedial and preventive measures is less effective than it could be if a better understanding of the problem existed. This research effort is designed to produce an understanding of the formation damage mechanisms responsible for deliverability loss and to examine the effect these mechanisms have on deliverability loss in a broad spectrum of gas-storage fields and reservoirs. The project objective is to provide (1) definitions of the mechanisms responsible for loss of deliverability in storage wells, (2) an outline of testing procedures that operators can use to deduce the type of damage mechanism, and (3) the basis for identifying procedures to prevent or remove damage. Candidate Selection The candidate selection process (Fig. 1) involves integrating information and expertise designed to select candidates based on reservoir type characterization, deliverability loss assessment, and well history/well records review. The objective of this task is to use existing data and classification of reservoir types outlined in the Mauer Engineering study (reservoir types R1 through R12) and document the magnitude of deliverability losses within fields operated by the cooperating companies. From this information, the broadest contrast examined was sandstone vs. carbonate rock type. In general, gas-storage reservoirs in sandstones make up 69% of the population. Carbonates comprise 27% and other storage media such as salt caverns and coal make up 4%. This data is illustrated in Fig. 2. P. 193^
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