TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAs drilling and completion technology advances, the trend to exploitation of gas reservoirs exhibiting ever lower permeabilities continues. This paper discusses issues associated with the identification of productive, low permeability, gas-producing formations and the successful completion and production of these reservoirs. For the purposes of this paper, a very low permeability gas reservoir is defined as a formation having an in-situ matrix permeability to gas of 0.5 mD or less. Criteria are presented for identifying economic absolute permeability cutoffs for low permeability gas-bearing formations. Very low permeability gas reservoirs are typically in a state of capillary undersaturation where the initial water (and sometimes oil) saturation is less than would be expected from conventional capillary mechanics for the pore system under consideration. These formations are commonly referred to as dehydrated or desiccated formations and have been documented on a worldwide basis. Retention of fluids (phase trapping) is discussed as one of the major mechanisms of reduced productivity, even in successfully fractured completions in these types of formations. As well, a variety of diagnostic and remedial treatment options are presented.

Gas storage reservoirs are used worldwide to store produced natural gasduring periods of low demand for use during periods of high demand. These formations are often depleted natural gas reservoirs. Proper selection of a gas storage reservoir is important to allow proper and economic operation of the project on a long-term basis. This paper describes issues which need to betaken into consideration from a reservoir perspective when considering the development of a gas storage reservoir. These issues include the proper containment of the injected gas, maintaining injectivity and productivity overlong-term operations, and problems which may be associated with the presence of free water or hydrocarbons in the storage reservoir (both mobile and immobile)as well as formation damage issues that often surround the drilling andcompletion of new wells in the gas storage reservoirs for development purposes. Introduction Gas storage reservoirs are used on a worldwide basis for the storage ofnatural gas for use in periods of peak consumption, generally in the colder portions of the year when gas demand for heating is higher. Storage reservoirs are also used to buffer periods of peak demand and prevent disruption of supplies during mechanical or other problems in producing fields. Gas storage reservoirs generally consist of good to excellent quality formations which are often located spatially close to the ultimate demand source (i.e. major population centers). Most of these reservoirs represent natural gas pools which have been depleted below their abandonment pressureduring normal production operations, but are now used on a seasonal basis forgas storage. For a reservoir to be a candidate for gas storage, the following criteria must be satisfied:Sufficient reservoir volume to allow for storage of the required amountof gas without exceeding containment pressure constraints and without requiringun economic compression to high pressure levels.Satisfactory containment of the gas by competent upper and lower sealing caprock.Sufficient inherent permeability to allow injection and production at required delivery rates during peak demand periods.Limited sensitivity to reductions in permeability (and injectivity/productivity) due to:–presence of in-situ water (mobile or immobile)–presence of liquid hydrocarbons (mobile or immobile)–plugging of the near injector region by compressor lubricants or otherintroduced fluids–reservoir stress fluctuations during successive pressure cyclesAbsence of hydrogen sulphide gas (in-situ or bacterially generated)We must be able to drill an dcomplete additional wells in the formationas required with causing servere formation damange (due to the highly depleted pressure condition which may often exist in these reservoirs). The Typical Gas Storage Reservoir Gas storage reservoirs are generally high permeability clastics or carbonates (1000–10,000 mD in-situ permeability is common) existing at intermediate depths and temperatrues. In general, these reservoirs are depleted formations which originally contained dry (non-retrograde), sweet (no H2S) natural gas. Typically, these zones do not contain mobile water or active or partially active aquifers, oil legs or residual liquid hydrocarbon saturations, although this is not always the case.

Low permeability gas reservoirs often exhibit high resistivity and low initial water saturations. Reservoirs of this type may also be susceptible to problems associated with the retention of water or hydrocarbon based drilling and completion fluids, as well as the accumulation of hydrocarbon liquids from the production of rich retrograde gas systems. These phenomena are referred to as aqueous and hydrocarbon phase trapping and have been extensively discussed in the literature as a major source of reduced productivity in low permeability gas reservoirs. This paper briefly describes specific laboratory procedures which have been developed to diagnose problems with phase trapping for given reservoir applications. This allows for the selection of the optimum drilling and completion fluids and practices prior to the costly execution of a potentially ineffective or damaging treatment in the reservoir. Specific examples of tests results and detailed protocols based on extensive testing and refinement of lab procedures are presented.

During the drilling and completion phases, the primary mechanisms of near-wellbore formation damage can be attributed to the following factors:pore throat constriction caused by clay swelling, deflocculating due to incompatible fluids or clay migration;water blocking resulting in a reduction in relative permeability to hydrocarbons;plugging with drill solids and mud products; andloading of the reservoir with drilling or completion fluids. In tight reservoirs, phase trapping and water-blocking are believed to be the primary causes of near-wellbore formation damage, resulting in very low productivity. Clay swelling and phase trapping in tight gas reservoirs during drilling and completion have long been identified as major problems. Preventive measures have been discussed in literature; however, prevention of clay damage and phase trapping is not always possible or effective and curative measures may then become necessary. Several curative methods have been attempted and presented in literature with mixed success. A formation heat treatment (FHT) process has been developed in the last four years and initial field test results showed promise. The primary mechanisms of the FHT process are to vaporize blocked water, dehydrate clay-bound water, destroy clay lattices and possibly create micro fractures due to thermally induced stresses, with the objective of removing near-wellbore drilling induced skin damage. The objective of this laboratory study was to evaluate the feasibility of applying the formation heat treatment process on cores taken from a tight gas reservoir. The results indicate that the FHT stimulation at 649 ° C resulted in a 210% improvement in permeability from the baseline undamaged value and 675% improvement from the damaged (water-trapped) value. The post FHT waterflooding of the core still showed 50% improvement in permeability from the baseline value and 275% more than the watertrapped value. Laboratory results along with the field logistics are presented in this paper. Introduction Formation damage can occur at any time during the history of a well-from the initial drilling and completion of the wellbore through to the depletion of the reservoir during production. Operations such as drilling, completion, workovers, and stimulation, which expose the formation to a foreign fluid, may cause formation damage because of adverse wellbore-fluid to formation interactions. Such damage is usually severe in horizontal wells, because of the longer exposure of the wellbore to the offending fluids(1 – 7). During the drilling and completion phases, the primary mechanisms of near-wellbore formation damage can be explained by the following factors:Pore throat constriction, caused either by clay swelling due to incompatible fluids or by clay migration,Water blocking due to reduction in relative permeability to hydrocarbon,Plugging with drill solids and mud products,Loading of the reservoir with drilling or completion fluids. In tight gas reservoirs, formation damage, due to phase trapping and water blocking, has long been identified as a major problem. Preventive measures against this type of damage are not always possible or effective, and curative measures may then become necessary. Several curative methods have been attempted and presented in the literature(8–15).

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I-.cI8d for pr8SeIII81kxI by ~ SPE PIIvwn CamiII8e foIow8Ig r8'Iiew It .mmaIkIrI ca1C8I8d In .. ab8act SID'*Ied by VIe aullCW(s).CQIII8* It VIe peper,-, '-rd b.-I ~ by VIe SocIety of PeInJIeI8n EIvr-. n-~ 10 The Traps!! When addressing the potential productivity of the low permeability gas reservoir, three major issues are of paramount concern. 1. Does the reservoir exhibit sufficient initial permeability and pressure to facilitate economic gas production rates, even in

Initial saturations of hydrocarbons and water, that exist in porous media, control reserves in place and, in many cases, the deliverability/recovery of these reserves. Hence, their accurate determination is essential for proper economic and reservoir engineering evaluation and optimization.

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