Underground Gas Storage Project Research Articles

Caspian Experience Boosts Performance in Turkey’s Onshore UGS Project

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207011, “Healthy Caspian Experience Helps Boost Drilling Performance in Turkey’s Onshore UGS Project,” by Elchin Akbarli and Rufat Mammadbayli, SPE, SOCAR AQS. The paper has not been peer reviewed. _ In the complete paper, the authors describe an operator’s underground gas storage (UGS) project. The intent of the paper is to demonstrate the execution methodology and technologies that the company used to deliver the work on time and under budget. The authors outline planning, design, and drilling and completion strategies used during the execution phase. The authors add that the company’s experience in Caspian operations was of great benefit to the project. Introduction A plan was developed to expand a UGS facility in a salt cavern field. The main challenge of the project was the requirement to complete all wells within a short time frame with a limited budget while keeping the project economically feasible for the company without compromising safety and environmental protection. Geological risks and uncertainties required additional preliminary considerations, leading to a focus on the best methods available for the drilling and completion of 40 planned wells. A comprehensive cost analysis was performed to evaluate the approach. The operations were divided into three stages: tophole drilling, main drilling, and completion. Different types of rigs, with different capabilities depending upon the range of the work, were assigned for each phase. The plan involved three small truck-mounted mobile rigs to begin tophole drilling and run 30-in. conductor casings to isolate unconsolidated formations and freshwater zones. Then, six main rigs would be mobilized to perform the main stages of drilling; three completion rigs would finalize the project. The company’s Caspian experience applied to several technical aspects of the project, from optimization of drilling activities to planning and execution. The project presented many technical challenges, including geological hazards, deviation control, and strict requirements of well integrity for a long period of time. Rig Specifications for Drilling Stages A major decision point in the planning phase was to select different types of rigs to implement various drilling operations in a staged manner. Initially, 125-ton-capacity truck-mounted rigs began to drill 36-in. tophole sections and run 30-in. casings; then, the task was passed to main drilling rigs with installed 30-in. conductor casing. Top holes were drilled with three low-cost, low-capacity rigs to combat the high potential of lost-circulation problems that could be experienced with high-cost main drilling rigs. In the second stage, main drilling rigs with 225-ton and 300-ton capacity were involved for the next 26- and 17½-in. sections. In the third stage, low-capacity rigs were moved to the well locations to complete wells, either running the last leaching string of 10- and 7-in. casings or underreaming 12-in. to 17½-in. sections before running leaching strings.

Coupled hydro-mechanical simulation in the carbonate reservoir of a giant oil field in southwest Iran

The Asmari reservoir in southwest Iran has been producing oil continuously for over 50 years. However, due to an essential pressure decline, the reservoir is now a potential candidate for injection projects. The geomechanical analysis is essential for a successful injection operation to enhance reservoir production and address possible challenges. An accurate estimation of the injection pressure is necessary to maintain optimal conditions during the injection process and reduce possible risks. In this work, a coupled reservoir-geomechanical model, as well as rock mechanical tests, is performed to evaluate not only pressure variation and the associated in situ stress changes but also their potential influences on fault reactivation, reservoir–caprock stability, and surface displacement. For geomechanical evaluation, empirical correlations are derived between static and dynamic rock properties based on core data and existing petrophysical logs for the studied reservoir–caprock system. Based on the hydro-mechanical results, the maximum displacement is limited to the vicinity of the injection wells, where the highest pressure changes occur. The geomechanical analysis of the reservoir–caprock system shows that this system is stable until the injection pressure reaches 4.3× the initial reservoir pressure. Also, the injection pressure is not high enough to compromise the integrity of faults, indicating that the loading on the fault planes is too low to reactivate the pre-existing faults. The approach followed in this study can be applied to future field development strategies and feasibility considerations for CO2 sequestration and underground gas storage projects.

Pore and permeability properties of reservoir sandstone under a uniaxial compression CT test

For underground gas storage projects that use depleted gas reservoirs, cyclic gas injection will change the stress fields and cause rock deformation. In-depth knowledge of the stress-induced deformation of reservoir rocks is important for secure gas storage. In this study, we performed a uniaxial compression computed tomography (CT) test with a reservoir sandstone sample to investigate the influence of rock deformation on the pore and permeability properties. Based on scanned 3D images, we analyzed the axial strain evolution by using the digital volume correlation (DVC) technique and the variations in pore properties with the microstructures and permeability properties that were extracted by the pore network modeling method. The DVC analysis shows that strain localization develops gradually with increasing axial stress. The initial porosity distribution with sample height is inhomogeneous. The local porosity variations are not completely consistent with the global porosity variations under increasing axial stress. The level of inconsistency will decrease with increasing axial stress in both the volumetric compression and dilation stages. Increases in axial stress mainly induce the variations in pore numbers and pore volumes. The variations in pore connectivity are not significant. For the permeability evolution, X-ray CT scanning combined with pore network modeling can simulate the permeability decreases during volumetric compression. For high porosity sandstones (>15%), the permeability still decreases in the volumetric dilation stage due to grain size reductions and tortuosity increases. However, this technique has limitations in analyzing the permeability reductions in the volumetric dilation stage. The microcracks that are induced inside the grain particles are too small to be recognized. The variations in the relative gas and water permeabilities at different axial stresses are not significant.

Probabilistic-based geomechanical assessment of maximum operating pressure for an underground gas storage reservoir, NW China

One of the most cost-effective ways to increase deliverability and working gas capacity in underground gas storage (UGS) reservoirs is to operate the gas storage at higher pressure (increased delta pressure). Maximum operating pressure (MOP) for a gas storage reservoir depends on several geomechanical factors, including in-situ stresses, stresses induced by local and global pressure changes in the storage reservoir, and the stabilities of the caprock and faults. PetroChina’s Hutubi (HTB) gas storage site is located in the west gate of China’s west–east gas pipeline project. Multiple major faults intersect the gas storage reservoir and caprock, which pose safety concerns for increasing the gas storage pressure. The typical practice in an HTB storage site has been to operate gas storage pressures at levels equal to the original reservoir pressure because of concerns related to caprock integrity and fault stability. To investigate the possibilities of increasing the gas storage pressure, a comprehensive geomechanical study has been conducted. By utilizing the data from rock mechanics laboratory testing, in-situ stress measurements, 3D field-specific geomechanical models, and coupled reservoir-geomechanical simulations, this paper presents probabilistic risk assessment of fault slippage in response to injection-related increases in pore pressure. Uncertainties of relevant geomechanical parameters, such as the frictional strengths of faults, orientation, and magnitudes of in-situ stresses, have been incorporated through Monte Carlo simulations. The authors find that: (1) fault slippage is the controlling factor which determines the limit of MOP at a HTB gas storage site; (2) increasing the gas storage pressure by 12.5% above the initial reservoir pressure (34.5 MPa) leads to approximately 0.6% probability of fault instability that could provide a leakage pathway. Thus, from a geomechanical perspective, operating the storage pressure at initial reservoir pressure at a HTB gas storage field is an overly conservative approach that leads to under-utilization of the existing storage capability. This paper provides the first integrative geomechanical study for increasing MOP for large underground gas storage reservoir in China. The methodology as well as comprehensive data repository are potential sources for future geomechanical studies on similar underground gas storage projects.

Underground gas storage project at Welton oilfield, Lincolnshire: Local perspectives and responses to planning, environmental and community safety issues

Abstract This paper describes the research undertaken by two local councillors to assess the proposed underground gas storage (UGS) scheme at Welton oilfield, Lincolnshire and the implications for the local community. Compared to the US, where over 300 operational gas storage facilities in onshore depleted fields exist, this form of gas storage is in its infancy in the UK. This has proved to be a challenge for the various agencies involved in the planning process. The councillors have identified a number of planning and safety issues which merit further consideration, including the applicability of the control of major accident hazards (COMAH) regulations, well integrity and the effects of re-pressurization of the oilfield. The proposed UGS facility is in close proximity to residential areas and concern amongst local residents is considerable. The councillors believe that their research has shown that insufficient attention has so far been given to community safety issues. A full and thorough assessment of all potential risks associated with this particular type of UGS needs to be undertaken and appropriate safeguards put in place to protect the local community.

Technology Focus: Reservoir Performance and Monitoring (September 2008)

Technology Focus The draft European Directive for carbon capture and sequestration requires monitoring of potential leakage from CO2-storage sites. In this case, monitoring is a method of improving efficiency and will be mandatory for obtaining permission for such projects. Whereas monitoring the movement of the CO2 plume offshore can be achieved at reasonable costs, onshore monitoring leads to high costs and difficulties because of disturbance of residents if seismic is used. Several potential CO2-storage sites are onshore; therefore, monitoring methods that are low-cost and have a limited effect on the public are required. Conventional hydrocarbon production will benefit from this mandatory push for new technology. One such method might be the use of microgravity, which recently was used successfully to monitor the movement of gas in an underground gas-storage project. By advancing this technology, its application envelope might expand even further into miscible- or immiscible-gas-injection enhanced-oil-recovery projects. Another method used increasingly for monitoring is microseismic. Induced microearthquakes are considered the result of slippage or tensile deformation and can be detected at nearby seismic receivers. Even though the effects are not understood well, in tight gas formations, microseismics is used to monitor the direction and growth of induced fractures. The first featured paper shows the expansion of this technology into other hydrocarbon-production activities. Less than a decade ago, the hydrocarbon-production industry discussed ways to cope with a world of low oil prices. This situation has changed dramatically. To optimize income from current high hydrocarbon prices, well-productivity loss from impairment must be minimized. The second featured paper describes a method of detecting such underperforming wells in real time. Assuming that high hydrocarbon prices prevail, unconventional hydrocarbon resources, of which large quantities exist, come into focus. Today, hydrocarbons such as bitumen or shale gas, which for a long period of time were produced in relatively small quantities compared with conventional hydrocarbons, are high on the agenda of oil- and gas-producing companies. To date, methane hydrates are considered to be one of the most unconventional resources with large hydrocarbon volumes in place. The third paper discusses how these reservoirs could be produced. Reservoir Performance and Monitoring additional reading available at the SPE eLibrary: www.spe.org IPTC 11370 • "Seawater in Chalk: An EOR and Compaction Fluid" by Tor Austad, University of Stavanger, et al. IPTC 11375 • "Reservoir Connectivity: Definitions, Examples, and Strategies" by John W. Snedden, ExxonMobil, et al. Additional reading available at OnePetro: www.onepetro.org OTC 19445 • "Fiber-Optic 4C Seabed Cable for Permanent Reservoir Monitoring" by Steve Maas, Petroleum Geo-Services, et al.

A Numerical Simulation Study on Mixing of Inert Cushion Gas with Working Gas in an Underground Gas Storage Reservoir

The cushion gas, providing the pressure energy necessary for withdrawal of working gas, makes up the largest part of the investment in underground gas storage projects. The suggested method of reducing this cost is the replacement of some part of the cushion gas with less expensive inert gas, such as nitrogen. In the replacement, there might be some problems due to mixing between natural gas and inert gas. Turkey has sharply increasing demand for natural gas. The constant imported gas and varying demand throughout the year due to the distinct seasons in the region are the reasons for severe need for gas storage in Turkey. There are no underground storage units in Turkey, but two gas reservoirs in the Thrace basin grant the potential for gas storage. From this point of view, the gas mixing problem is investigated for a typical gas reservoir by coupled use of a gas reservoir simulator and a transport model. A two-dimensional (2-D), single-phase numerical gas reservoir simulator is developed to obtain the pressure distribution during production and injection cycles. The velocity distribution is found by using these pressures. Then the two-dimensional transport model is used to calculate nitrogen concentrations around the injection wells. Both models are used effectively for controlling the mixing problem in an underground gas storage reservoir.

Norg Underground Gas Storage: an Integrated 3-D Geological and Geophysical Reservoir Modeling Study

The Netherlands have an extensive gas distribution infrastructure supplying 80 x 10[sup 9] m[sup 3] per annum to the domestic and European market. The capacity requirement exceeds 600 x 10[sup 6] sm[sup 3]/d, of which 430 x 10[sup 6] sm[sup 3]/d is provided by the giant Groningen gas field. The Groningen field will soon reach a pressure at which this capacity can no longer be met without considerable investments. It will also become difficult to maintain the market gas quality, because of the increasing supply from small fields with widely varying gas qualities. Underground Gas Storage (UGS) will satisfy both capacity and gas-quality requirements. This UGS must eventually store 4.5 x 10[sup 9] m[sup 3] with injection/production capacities of 36/80-100 x 10[sup 6] sm[sup 3]/d, making it one of the largest UGS projects in the world. These extremely high-capacity requirements demand both high-matrix permeability and good understanding of vertical and lateral reservoir continuity. Matrix permeability is predictable due to the close relationship with the lithofacies defined within the primary Rotliegende depositional model. Minor faults, identified on three-dimensional (3-D) seismic attribute maps, represent potential transmissibility impairment zones, compartmentalizing the reservoir. This was initially suggested by core fracture studies and confirmed bymore » a subsequent field shut-in and pressure buildup test. Lithofacies and seismic structural data are integrated within a computerized reservoir geological modeling system known as [open quotes]Monarch[close quotes] to provide a highly detailed 3-D permeability model that is then tranformed into a model for dynamic reservoir simulation. The results confirm the required working volume for the UGS operation and provide a basis for the initial field development planning.« less

Evaluation of Formation Damage Caused by Drilling Fluids, Specifically in Pressure-Reduced Formations

This paper describes a method for evaluating formation damage caused by drilling fluids in reservoirs that may have pressure considerably lower than hydrostatic pressure. The problem is of specific interest for EOR and/or underground gas storage projects. The method, which is flexible and practically oriented, allows formation-damage evaluation under the following conditions: less than or equal to1,400-psi (9.7-MPa) differential pressure, less than or equal to300/sup 0/F (150/sup 0/C) temperature, 6-ft/sec (2-m/s) annular velocity, 0.4- to 1-in. (1- to 2.5-cm) core diameter, and 10-in. (25-cm) length.

Subsurface Storage and Disposal in Illinoisa

ABSTRACTThe storage of both liquids and gases in underground strata has become rather common in Illinois.The problem of disposal of fluid industrial wastes has caused greatest concern, especially for the possible effects on ground‐water quality. Necessary precautions have been established in the requirements of the Illinois Environmental Protection Agency (IEPA) which has authority to control, prevent, and abate pollution of streams, lakes, ponds, and other surface and underground waters in the State. Before any construction can begin on storage in subsurface strata, a permit must be secured from the IEPA. Eight basic design policies have been adopted that have to be met before a construction permit will be issued.Sandstone, limestone, and dolomite are the basic lithologies most commonly considered as potential disposal reservoirs in Illinois. From well cores of such formations, essential laboratory studies are conducted defining the rate of fluid movement, porosity, and permeability of the rock and the pressure distribution within the aquifer.Plugging of the injection horizon is the most serious cause of damage to a fluid injection system and results from the forming of an impermeable deposit on the well bore or plugging in the formation itself. In either case the plugging may result from a number of listed causes.To date there have been four industrial waste disposal wells in Illinois. Variation in conditions is illustrated by these cases of disposal wells that have been authorized by the State.The first practical use of underground gas storage in Illinois was at Waterloo in 1950. Since then, the number of projects and their capacities have grown continuously. At the present time there are 24 underground gas storage projects. Gas injection pressures must be kept below the fracturing pressure of the caprock. In underground gas storage reservoirs in Illinois, injection pressures of approximately 0.55 psi per foot are often used.Secondary recovery by water flooding accounted for 73.4 percent of the total oil production in Illinois during 1968. In that year there were 880 active projects in Illinois with 13,107 water injection wells that injected 2581 million gallons of water.

Gas Storage in the Playa Del Rey Oil Field

Abstract To date, utility company underground storage of gas has generally beenrestricted to depleted dry gas fields. The Playa del Rey project is probablythe first to successfully store gas in a partially depleted oil reservoir withthe recovery of large volumes of gas at high rates as the main objective. Oilrecovery has been a secondary consideration. Problems encountered unusual to those of storage in a dry gas zone were:the removal and retardation of formation of emulsion,the up structuremovement of fluid during withdrawal periods which formed fluid blocks, andreservoir shrinkage resulting from encroachment of edgewater. The solution of these problems as outlined in the paper has resulted inincreasing the withdrawal rate from the original design capacity of 4,000 Mcfper hour to the current 10,000 Mcf per hour. Additional increase is anticipatedas the operations continue. Migration, reservoir performance, operational procedure and a historicalrecord are included to make this a resume of the project from its war-timeinception in 1942 to the first of 1952. Introduction The Playa del Rey underground gas storage project is probably the firstproject in which gas has been stored in a partially depleted oil reservoir, with the recovery of large volumes of gas at high rates as the main objectiveand the recovery of oil a secondary consideration. Problems unusual to those ofstorage in dry gas zones have made this a pioneer endeavor. The total storage capacity of approximately 1,500,000 Mcf of this reservoiris small in comparison with other underground gas storage projects. However, bystudy and experiment the deliverability into transmission lines, operating atpressures in excess of 150 lbs., has been nearly tripled in the past threeyears to the current 10,000 Mcf per hour rate, without the life of compression.It is anticipated this rate will gradually increase as additional fluid isremoved from the formation. Location and History Playa del Rey is located on Santa Monica Bay about two miles south of thebeach community of Venice and 15 miles southwest of the center of the City ofLos Angeles. Fig. 1. T.P. 3669