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Energy
Formation Screening to Minimize Permeability Impairment Associated With Acid Gas Or Sour Gas Injection/Disposal
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Thomas, F.B. (Hycal Energy Research Laboratories Ltd.) | Bennion, D.W. (Hycal Energy Research Laboratories Ltd.) | Bietz, R.F. (Hycal Energy Research Laboratories Ltd.)
Abstract High acid gas content streams, consisting primarily of carbon dioxide, hydrogen sulphide or a combination of both are commonly generated as by-products of the sweetening process used to bring many produced gases and solution gases to pipeline specifications for sales and transport. Typically, sour gas has been extracted from acid gases through the use of Claus or other types of elemental sulphur reduction processes, the sulphur sold or stockpiled, and the residual carbon dioxide vented to atmosphere. With depressed prices for the commercial sale of sulphur and environmental concerns with the emission of large volumes of greenhouse gases, industry has shown considerable interest in the feasibility of re-injecting acid gas from sweetening processes, either back into the original producing formation, or into selected disposal zones which may consist of aquifers or previously depleted oil or gas zones. A major concern with the reinjection process is the potential for formation damage and reduced injectivity in the vicinity of the acid gas injection/disposal wells. This paper discusses screening criteria for reservoir selection for zones suitable for acid/sour gas re-injection or disposal, and highlights potential areas of concern for reduced injectivity. Such phenomena include acid gas induced formation dissolution, fines migration, precipitation and scale potential, oil or condensate banking and plugging, asphaltene and elemental sulphur deposition, hydrate plugging and multiphase flow associated with acid gas compression. Variations on acid gas injection schemes, such as concurrent contacting with produced water at elevated pressures and subsequent disposal of the sour water, will also be discussed and potential damage concerns highlighted. A variety of screening and laboratory tests and results will be presented which illustrate the various damage mechanisms outlined and provide a specific set of design criteria to evaluate the feasibility of an acid gas injection/disposal operation. Introduction Acid gases [gases which contain carbon dioxide (CO2) and hydrogen sulphide (H2S)] are produced from many formations as either free gas or liberated solution gas from sour oils. These gases must be "sweetened" to selectively remove the acid gas components before the gas can be transported and sold for commercial use. A variety of sweetening processes are used to remove acid gas components (amine extraction being the most common). The sweetening process results in the production of acid gasfree "sales" gas, and a rich waste gas stream consisting of virtually pure CO2 and H2S (commonly referred to as concentrated acid gas). In the past, a variety of techniques have been used to handle acid gas streams, most of them primarily concerned with the reduction of the extremely toxic hydrogen sulphide to an inert/non-toxic reaction product. The most common technique is the Claus reaction process where the H2S gas in the acid gas stream is catalytically converted to elemental sulphur. This process was an economic one in the past, particularly in regimes of good sulphur commodity prices. Many operators deliberately attempted to exploit reservoirs containing high concentrations of H2S with sulphur recovery as the primary motivating factor.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Remediation of Water And Hydrocarbon Phase Trapping Problems In Low Permeability Gas Reservoirs
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Thomas, F.B. (Hycal Energy Research Laboratories Ltd.) | Bietz, R.F. (Hycal Energy Research Laboratories Ltd.) | Bennion, D.W. (Hycal Energy Research Laboratories Ltd.)
Abstract Aqueous and hydrocarbon phase traps can occur in porous media when water- or oil-based fluids come into contact with a formation which exhibits a "subirreducible" initial liquid saturation of the phase. of interest. This commonly occurs with waterbased fluids in many low permeability desiccated gas bearing formations and in depleted conditionsinrich gas retrograde condensate reservoirs. This paper documents how phase traps are induced by direct displacement, countercurrent imbibition or depletion effects, and presents techniques for diagnosing whether a reservoir is a candidate for an aqueous phase trapping problem. Techniques to minimize problems with aqueous and hydrocarbon phase trapping are reviewed, followed by discussion of methods to reduce or remove the effect of existing phase traps, such. as increased drawdown, alteration of 1FT, alteration of pore geometry or direct removal methods. A brief discussion of laboratory techniques used to screen the optimum processfor selection are also presented. Introduction The phenomena of permanent entrainment of extraneous or in situ generated aqueous- or hydrocarbon-based liquids in porous media has been documented in the literature as a mechanism for significant permeability impairment in low permeability intercrystalline sandstone and carbonate formations . Phase traps normally occur when a water- or hydrocarbonbased fluid is either forced or imbibed into porous media with a subirreducible water or hydrocarbon saturation (i.e., at a saturation less than the irreducible liquid saturation given the geometry, wettability, and capillary mechanics of the system under consideration). Subirreducible hydrocarbon saturations are common in rich gas retrograde systems existing in a sub-dewpoint condition, or in mature gas fields which may have migrated into previously oilsaturated strata. Subirreducible water saturations in low permeability gas reservoirs are also quite common. The mechanism for the establishment of a subirreducible water saturation in a low permeability gas-bearing reservoir is the subject of some controversy. The dominant mechanism is thought to be desiccation motivated by a large regional migration of gas under conditions of increasing temperature and pressure through a given reservoir area over a long period of geological time. The basic mechanism of a phase trap is created by the relative permeability effect associated with an increase in the immobile water or hydrocarbon saturation. This phenomena is illustrated on a pore scale in Figure 1 and from a mechanistic point of vie\v as Figure 2. The severity of the phase trap is strongly influenced by:The magnitude of the difference between the "initial" and final trapped "irreducible" liquid saturation which exists in the porous media. The greater this difference, the larger the adverse relative permeability effect and the greater the potential reduction in permeability. The configuration of the gas or oil phase relative permeability curves at low liquid saturation levels. The more adverse the configuration of these curves (i.e., the more convex the relative permeability curve), the more significant the reduction in permeability for a given increase in trapped liquid saturation. The depth of invasion of the trapped phase. The greater the volume of fluid lost and deeper the invasion, the more difficult the mobilization of this fluid becomes.
Abstract Recent improvements in the. speed. of numerical compositional simulators has made it possible to use a large number of grid blocks to model condensate reservoirs, volatile reservoirs, and gas injection projects. This paper discusses techniques for choosing pseudo components so as to use four to five pseudo components for the simulations. It also discusses the condensate dropout in the reservoir and its effect on the productivity of individual producing wells. The methods for characterizing fracture networks in a naturally fractured reservoir are presented and other parameters which affect hydrocarbon recovery are discussed as part of a parametric study. Introduction In recent years wells have been drilled to greater depths, resulting in the discovery of gas condensate reservoirs and volatile oil reservoirs at relatively high temperatures. A large amount of research has been conducted to investigate productivity from these oil reservoirs. This research has investigated how to tune an equation of state so as to match the actual phase behaviour which is occurring within a reservoir. Studies have reported on the effects of interfacial tension and velocity on gas-oil relative permeability curves. These studies indicate that bench type gas-oil and water-oil relative permeabilities are not applicable to predicting the performance of individual wells in gas condensate reservoirs. Well test data and recent advances in well logging procedures using well-bore imaging techniques have provided tools to better characterize the fracture system which exists in naturally fractured reservoirs. These data have been used in conjunction with stochastic models to describe the fracture network inside of these reservoirs. A parametric study using a number of variables was conducted for this paper. The results from this parametric study are useful in history matching to determine those parameters which, when adjusted, will have the greatest effect on the performance of the reservoir. This study will also suggest modifications which need to be made to numerical simulators so as to better simulate the actual mechanism which are occurring in gas condensate reservoirs. Mechanism of Flow in Naturally Fractured Reservoirs Fluid flow in naturally fractured reservoirs differs significantly from that in a single porosity system. The numerical simulator breaks the reservoir into two different systems: one, a system of matrix blocks which mayor may not have capillary contact and the other, a network of fractures. The simulation assumes that most of the flow to the wells will occur through the fracture network which contains a relatively small fluid volume, but high permeability, and that the bulk of the hydrocarbon fluids are contained within the matrix blocks. As reservoir pressure is depleted, the fluids are expelled from the blocks into the fracture system, which conveys them to the producing wells. Gas condensate reservoirs initially are at pressures at or above the dewpoint. Once the pressure has been depleted below the dewpoint, liquid will condense and two phases will be present. When these two phases are present the liquid will not flow in either the matrix or the fracture system until a critical condensate saturation is obtained.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Special Core Analysis Designed to Minimize Formation Damage Associated With Vertical/Horizontal Drilling Applications
Doane, R.D. (Hycal Energy Research Laboratories Ltd.) | Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Thomas, F.B. (Hycal Energy Research Laboratories Ltd.) | Bietz, R.R. (Hycal Energy Research Laboratories Ltd.) | Bennion, D.W. (Hycal Energy Research Laboratories Ltd.)
Abstract Laboratory testing of core material to optimize drilling fluid composition and procedures has been used for many years to minimize invasive formation damage of a mechanical, chemical or biological nature which can occur during the drilling of horizontal or vertical wells. This paper discusses the limitations of past practices such as the use of non-representative core or fluids, non-preserved or non-restored state core, ambient conditions of temperature and overburden pressure, direct injection of muds/filtrates into samples and unrealistically high drawdown gradients for cleanup. The paper describes the current technology used to eliminate many of these concerns and also to extend drilling fluid evaluation technology to extremely heterogeneous carbonate and sandstone formations, fractured formations and specific test equipment and procedures used to evaluate the effectiveness and utility of underbalanced drilling programs. Introduction Formation damage occurring during the drilling of horizontal or vertical wells can be a significant cause of ultimate reduced productivity in both oil and gas bearing formations. In some cases a combination of petrographic and special core analysis techniques is used to evaluate the potential effectiveness of proposed drilling fluids and procedures, prior to incurring the actual cost and risk of implementation. These tests are conducted to obtain a better assessment of the risk associated with the use of proposed drilling fluids and to optimize the fluid and procedures which will be utilized in a given horizontal or vertical well operation to maximize ultimate productivity of oil or gas. Considerable advances have been made in recent years in both the execution and interpretation of the results of laboratory coreflow tests to obtain representative results for effective field design of well drilling programs. This paper reviews test procedures used in the past, describes potential problems with these test procedures, and outlines current laboratory technology with respect to specialized laboratory testing to evaluate drilling induced damage for vertical and horizontal well applications. Common Mechanisms of Formation Damage During Overbalanced and Underbalanced Drilling Operations A number of authors have provided a detailed discussion of potential formation damage mechanisms which may occur during overbalanced and underbalanced drilling operations. A summary of this work is provided in the literature. These mechanisms include: Mechanically Induced Formation Damage Physical migration of in situ fines and mobile particulates. The introduction of extraneous solids of either an artificial nature (i.e., weighting agents, fluid loss agents, or artificial bridging agents) or naturally occurring drill solids generated by the milling action of the drill bit on the formation. Relative permeability effects associated with the entrainment of extraneous aqueous or hydrocarbon phases within the porous medium. Formation damage effects associated with the use of extreme underbalance or overbalance pressures and associated fines migration or spontaneous imbibition phenomena. Direct mechanical glazing phenomena associated with bitformation interactions. This particular damage mechanism is usually associated with gas drill operations where high bitrock temperatures commonly occur.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
This paper (SPE 52889) was revised for publication from paper SPE 35242, first presented at the 1996 SPE Permian Basin Oil and Gas Recovery Conference held in Midland, Texas, 27-29 March. Original manuscript received for review 11 April 1996. Revised manuscript received 29 April 1997. Paper peer approved 17 April 1998. Summary Underbalanced drilling (UBD) has been used with increasing frequency to minimize problems associated with invasive formation damage, which often greatly reduce the productivity of oil and gas reservoirs, particularly in openhole horizontal well applications. UBD, when properly designed and executed, minimizes or eliminates problems associated with the invasion of particulate matter into the formation as well as a multitude of other problems such as adverse clay reactions, phase trapping, precipitation, and emulsification, which can be caused by the invasion of incompatible mud filtrates in an overbalanced condition. In many UBD operations, additional benefits are seen because of a reduction in drilling time, greater rates of penetration, increased bit life, a rapid indication of productive reservoir zones, and the potential for dynamic flow testing while drilling. UBD is not a solution for all formation damage problems. Damage caused by poorly designed and/or executed UBD programs can rival or even greatly exceed that which may occur with a well-designed conventional overbalanced drilling program. Potential downsides and damage mechanisms associated with UBD will be discussed. These include the following.Increased cost and safety concerns. Difficulty in maintaining a continuously underbalanced condition Spontaneous imbibition and countercurrent imbibition effects. Glazing, mashing, and mechanically induced wellbore damage. Macroporosity gravity-induced invasion. Difficulty of application in zones of extreme pressure and permeability. Political/career risk associated with championing a new and potentially risky technology. We discuss reservoir parameters required to design an effective underbalanced or overbalanced drilling program, laboratory screening procedures to ascertain the effectiveness of UBD in a specific application and review the types of reservoirs that often present good applications for UBD technology. P. 214
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract Poor injection water quality is a prime factor in the reduction in injectivity in many water injection and disposal wells. These reductions in injectivity often result in costly workovers, stimulation jobs and recompletions, or, in many cases, the uncontrolled fracturing of wells by high bottomhole pressures resulting in poor water injection conformance and reduced overall sweep efficiency and recovery. This paper discusses many commonly occurring water quality issues and how they impact injectivity, including damage due to injection of suspended solids, fines migration, clay swelling and deflocculation, formation dissolution, chemical adsorption and wettability alterations, relative permeability effects associated with the injection of skim oil or grease and the injection of entrained free gas, biologically and bacterially induced damage, formation of insoluble scales and precipitates, emulsification, wax and asphaltene deposition. Screening criteria are presented to allow for a rigorous evaluation of a particular injection water source to investigate potential areas of sensitivity and to attempt to minimize problems associated with impaired injectivity. Introduction Water injection processes are utilized throughout the world to dispose of produced aqueous fluids and as a means of increasing the recovery efficiency in many oil reservoirs. A key factor in the success of these operations is contingent on being able to inject a sufficient quantity of the water of interest into the target zone. Injectivity can be restricted by:Poor inherent reservoir quality; Insufficient pay or contact of the pay zone of interest by the injection well; Formation damage effects associated with the actual water injection process. The subject matter of this paper will concentrate on the topic of injection water quality and how this factor relates to impaired injectivity. Impaired injectivity causes problems in that it restricts the volume of water which can be injected in a given well (causing potential problems with voidage replacement for a waterflood, or the buildup on surface of a large volume of produced water in a disposal operation). Often downhole injection pressure may exceed fracture pressure causing the initiation and propagation of uncontrolled induced fractures. These fractures may reduce overall efficiency of the waterflood process by lowering areal sweep efficiency and possibly directing injected fluids out of the zones of interest. However, in some cases, fractures may provide connections to zones of interest. Almost all problems associated with impaired injectivity can ultimately be related back to problems associated with water quality. Potential damage mechanisms which can be associated with water injection processes include:Mechanically induced damage, including: a) Injection of solids, b) Velocity induced damage (fines migration) and settling, where fines are present Injection water/formation rock interactions, including: a) Clay swelling, b) Clay deflocculation, c) Formation dissolution, d) Chemical adsorption/wettability alterations. Relative permeability effects, including: a) Skim oil entrainment, b) Free gas entrainment. Biologically induced impairment, including: a) Bacterial entrainment and growth. Injection water/in situ fluid interactions, including: a) Formation of insoluble scales, b) Emulsification and emulsion blocks, c) Precipitation, d) Wax/asphaltene deposition.
- North America > United States > California (0.46)
- North America > Canada > Alberta (0.30)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Water And Hydrocarbon Phase Trapping In Porous Media-Diagnosis, Prevention And Treatment
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Thomas, F.B. (Hycal Energy Research Laboratories Ltd.) | Bietz, R.F. (Hycal Energy Research Laboratories Ltd.) | Bennion, D.W. (Hycal Energy Research Laboratories Ltd.)
Abstract The entrapment of extraneous phases within porous media can occur in a number of different situations during drilling, completion, workover and production operations. The introduction of an additional immiscible phase, or an increase in an existing phase saturation within porous media can cause deleterious relative permeability effects which can substantially impact the permeability and relative permeability to oil or gas. This phenomenon is commonly described as aqueous phase trapping or hydrocarbon phase trapping, depending on the situation under consideration. This paper describes specific conditions required for the establishment of aqueous and hydrocarbon phase traps and provides diagnostic equations to evaluate the potential severity of an aqueous phase trap in a given reservoir situation. Specific procedures are recommended for the prevention of aqueous phase traps during drilling, completion and production operations and, in a situation where phase traps are determined to exist in a reservoir, a variety of treatment techniques are presented to attempt to remove or reduce the severity of the aqueous or hydrocarbon phase trapping phenomenon. Introduction Aqueous phase trapping and hydrocarbon phase trapping represent a significant mechanism of impaired productivity in many oil and gas reservoirs in various locations throughout the world. Bennion et al. (1994) have provided a detailed discussion of the basic mechanisms of aqueous and hydrocarbon phase trapping and associated reductions in permeability. Aqueous phase trapping can occur in both oil and gas reservoirs and may be associated with reservoir situations where the reservoir exhibits a sub-irreducible initial water saturation. Specific additional documentation on subirreducible water saturation reservoirs is documented by Katz et al. (1982) and Masters et al. (1984). Hydrocarbon phase traps may be established in gas reservoir applications where extraneous immiscible hydrocarbon phases are introduced into the reservoir, or in retrograde condensate reservoir applications where the reservoir is produced at some pressure below the dewpoint resulting in the accumulation of liquid retrograde condensate within the pore space. This paper discusses various types of phase trapping and provides criteria for the diagnosis of the potential severity of a reservoir to be susceptible to aqueous phase traps. Additional discussion is then presented with respect to the prevention of aqueous and hydrocarbon phase traps in different reservoir operational situations and potential remediation of oil and gas reservoirs where aqueous or hydrocarbon phase traps have already been established. Mechanisms of Aqueous Phase Trapping Figure 1 provides a schematic illustration of the establishment of an aqueous phase trap within a low permeability gas reservoir application. The initial basis for the establishment of an aqueous phase trap is a reservoir which exists at what is classified as a subirreducible saturation, where the initial water saturation in the reservoir is less than what would be typically quantified as the irreducible water saturation which would exist in the porous media under the prevailing capillary conditions. Sub-irreducible saturations are postulated to be established by a combination of dehydration, desiccation, compaction and diagenetic effects which occur over the life of certain reservoirs.
- North America > United States (1.00)
- North America > Canada > Alberta (0.47)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
Abstract Formation damage is a very reservoir specific process, but extensive studies indicate that generalities can often be drawn with respect to certain types and mechanisms of damage which are more prevalent with various reservoir types. This paper provides a mechanistic discussion of various types of formation damage common to horizontal wells, such as fluid-fluid and rock-fluid incompatibilities, solids invasion, effect of overbalance pressure, aqueous phase trapping, chemical adsorption, wettability alteration, microbiological activity, and fines migration. These phenomena are discussed and how they specifically relate to the following formation types:Clean and dirty homogeneous sands. Clean and dirty laminated sands. Unconsolidated sands. Fractured sands. Homogeneous carbonates. Fractured carbonates. Vugular carbonates. Recommendations for various fluid types and procedures which have experienced success in certain situations are also presented. Laboratory testing of fluids and representative core samples is highlighted as a potential diagnostic tool to select the optimum fluids for drilling, completion, stimulation and workover treatments. Use of these guidelines can, in many cases, narrow the choice of potential fluids considered for use in a given lithofacies type and increase the efficiency of the optimization process. Introduction Horizontal drilling is being utilized in an ever increasing fashion to exploit reservoirs exhibiting thin pay zones, problems with water or gas coning, to obtain greater reservoir exposure and to maximize the productive potential of naturally fractured reservoirs. Reductions in the productivity of these horizontal wells due to improperly or inadequately designed drilling, completion or workover programs is a frequent occurrance. This paper documents common areas for potential reductions in the productivity of horizontal wells completed in oil or gas bearing formations due to invasive formation damage and provides general criteria for the design and selection of fluids and operating programs to minimize potential damage. Invasive Formation Damage Formation damage can be described as any phenomenon induced by the drilling, completion or stimulation process or by regular operations resulting in a permanent reduction in the productivity of a producing oil or gas well or the reduction in the injectivity of a water or gas injection well. Invasive formation damage can occur by the introduction of:Foreign potentially incompatible fluids into the formation. Natural or artificial solids. Extraneous immiscible phases. Physical mechanical damage. Further information on some of the specific mechanisms of these various types of invasive damage will be elucidated upon later in the paper. Formation Damage in Horizontal vs. Vertical Wells A detailed discussion of mechanisms of formation damage in horizontal wells has been presented in the literature. Formation damage tends to be more significant in horizontal vs. vertical wells for a number of reasons, some of these being:Longer fluid exposure time to the formation during drilling and greater potential depth of invasion in situations where sustained fluid and solids losses to the formation are apparent.
- North America > United States (0.68)
- Europe > Norway > Norwegian Sea (0.25)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.91)
Formation Screening to Minimize Permeability Impairment Associated With Acid Gas Or Sour Gas Injection/Disposal
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Thomas, E.B. (Hycal Energy Research Laboratories Ltd.) | Bennion, D.W. (Hycal Energy Research Laboratories Ltd.) | Bietz, R.E. (Hycal Energy Research Laboratories Ltd.)
Abstract High acid gas content streams, consisting primarily of carbon dioxide, hydrogen sulphide or a combination of both are commonly generated as a by-product of the sweetening process used to bring many produced gases and solution gases to pipeline specifications for sales and transport. Typically, sour gas has been extractedfrom acid gases through the use of Claus or other types of elemental sulphur reduction processes, the sulphur sold or stockpiled, and the residual carbon dioxide vented to atmosphere. With depressed prices for the commercial sale of sulphur and environmental concerns with the emission of large volumes of greenhouse gases, considerable interest has been extant in the industry into the feasibility of the reinjection of acid gas from sweetening processes, either back into the original producing formation, or into selected disposal zones which may consist of aquifers or depleted previously produced oil or gas zones. A major concern with the re-injection process is the potential for formation damage and reduced injectivity in the vicinity of the acid gas injection disposal wells, as well as reservoir screening criteria with respect to suitable gas containment concerning the subsequent migration of injected acid gases. This paper discusses screening criteria for reservoir selection for zones suitable for acid/sour gas re-injection Or disposal, and highlights potential areas of concern for reduced injectivity. Such phenomena include acid gas induced formation dissolution, fines migration, precipitation and scale potential, oil or condensate banking and plugging, asphaltene and elemental sulphur deposition, hydrate plugging and multiphase flow phenomena associated with acid gas compression phenomena. Variations on acid gas injection schemes, such as concurrent contacting with produced water at elevated pressures and subsequent disposal of the Sour water, will also be discussed andpotential damage concerns highlighted A variety of screening and laboratory tests and results will be presented which illustrate the various damage mechanisms outlined and provide a specific set of design criteria to evaluate the feasibility of an acid gas injection/disposal operation. Introduction Acid gases (gases which contain carbon dioxide (CO2) and hydrogen sulphide (H2S)) are produced from many formations as either free gas or liberated solution gas from sour oils. These gases must be "sweetened" to selectively remove the acid gas components before the gas can be transported and sold for commercial use. A variety of sweetening processes are used to remove acid gas components (amine extraction being the most common). The sweetening process results in the production of acid gas-free "sales" gas, and a rich waste gas stream consisting of virtually pure CO2 and H2S (commonly referred to as concentrated acid gas). In the past, a variety of techniques have been used to handle acid gas streams, most of them primarily concerned with the reduction of the extremely toxic hydrogen sulphide to an inert/non-toxic reaction product. The most common technique is the Claus reaction process where the H2S gas in the acid gas stream is catalytically converted to elemental sulphur. This process was an economic one in the past, particularly when sulphur prices were in excess of $ 150/tonne. Many operators deliberately attempted to exploit reservoirs containing high concentrations of H2S with sulphur recovery, rather than the value of the sweet sales gas, being the primary motivating factor.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Abstract Recent improvements in the speed of numerical compositional simulators has made it possible to use a large number of gridblocks to model condensate reservoirs, volatile reservoirs, and gas injection projects. This paper discusses techniques for choosing pseudo components so as to use 4 – 5 pseudo components for the simulations. It also discusses the condensate dropout in the reservoir and its effect on the productivity of individual producing wells. The methods for characterizing fracture networks in a naturally fractured reservoir are presented and other parameters which affect hydrocarbon recovery are discussed as part of a parametric study. INTRODUCTION In recent years wells have been drilled to greater depths, resulting in the discovery of gas condensate reservoirs and volatile oil reservoirs at relatively high temperatures. Recently a large amount of research has been conducted to investigate productivity from these oil reservoirs. This research has investigated how to tune an equation of state so as to match the actual phase behavior which is occurring within a reservoir. Studies have reported on the effects of interfacial tension and velocity on gas-oil relative permeability curves. These studies indicate that bench type gas-oil and water-oil relative permeabilities are not applicable to predicting the performance of individual wells in gas condensate reservoirs. Well test data and recent advances in well logging procedures using well-bore imaging techniques have provided tools to better characterize the fracture system which exists in naturally fractured reservoirs. These data have been used in conjunction with stochastic models to describe the fracture network inside of these reservoirs. A parametric study using a number of variables was conducted for this paper. The results from this parametric study are useful in history matching to determine those parameters which, when adjusted, will have the greatest effect on the performance of the reservoir. This study will also suggest modifications which need to be made to numerical simulators so as to better simulate the actual mechanism which are occurring in gas condensate reservoirs. MECHANISM OF FLOW IN NATURALLY FRACTURED RESERVOIRS Fluid flow in naturally fractured reservoirs differs significantly from that in a single porosity system. The numerical simulator breaks the reservoir into two different systems, one a system of matrix blocks which mayor may not have capillary contact and a network of fractures. The simulator basically assumes that most of the flow to the wells will occur through the fracture network which contains a relatively small fluid volume, but high permeability, and that the bulk of the hydrocarbon fluids are contained within the matrix blocks. As reservoir pressure is depleted, the fluids are expelled from the blocks into the fracture system which conveys them to the producing wells. Gas condensate reservoirs initially are at pressures at or above the dewpoint. Once the pressure has been depleted below the dewpoint, liquid will condense and two phases will be present. Once these two phases are present the liquid will not flow in either the matrix or the fracture system until a critical condensate saturation is obtained.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.49)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)