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Abstract Slotted liners are used extensively in the majority of steam assisted gravity drainage (SAGD) operations conducted in Western Canada due to their superior mechanical strength and integrity in contrast to other mechanical sand-control devices. These liners are required because of the generally poorly or unconsolidated nature of the majority of formations in which SAGD applications are conducted. These liners can have a variety of configurations with varying slot density, slotting patterns, slot apertures and slot internal geometries. The overall objective of a successful slotted liner design is to ensure that the liner allows the maximum production of bitumen and other fluids with a minimum pressure drop, while retaining the majority of the formation sand and preventing infill of the horizontal section of the well with solids and erosion and failure of downhole pumps and surface equipment. This paper describes a detailed lab test protocol which was successfully developed over a number years for the design and evaluation of slot geometry for SAGD applications, describes test procedures used and quantifies some of the major mechanisms discovered that lead to the plugging of slots. It has been found that in addition to grain size of the sand under consideration and slot geometry, that clay content of the formation, flow velocity, wetting phase type and pH play crucial roles in the plugging mechanism of slotted liners. Clay plugging at the top portion of the slots has been found to be the dominant damage mechanism. Introduction SAGD is being used extensively in Western Canada and other areas in the world as an effective and economic means for the recovery of heavy oil and bitumen reserves and represents the current primary technology for the exploitation of this large hydrocarbon resource(1-5).
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.89)
- Geology > Mineral > Silicate > Phyllosilicate (0.76)
Abstract Gas condensate reservoirs exhibit complex coupling between phase behaviour, interfacial tension, velocity and pore size distribution. Appropriate characterization of the in situ fluids and relevant flow testing can provide valuable insight into gas condensate reservoir forecasting. The following insights were obtained during the course of this testing:The importance of path dependence was shown to be significant when creating equilibrium phases below saturation pressure for use in quantifying phase interference. Differences, due to compositional path, in API gravity of liquids in solution were quantified to be as much as 10 degrees, with molecular weight differences over 110 daltons. End-point saturations, such as trapped gas and residual condensate saturation, are sensitive to the level of interfacial tension (IFT). Critical condensate saturation was less sensitive to IFT (pressure). The two-phase injection approach and the protocol whereby explicit measurement of relative permeability is performed provide a very thorough gas-condensate reservoir data set, which are amenable for use in simulation and reservoir production forecasting. Background This paper discusses performance of gas condensate reservoirs. These reservoirs have a reservoir temperature located between the critical point and the cricondentherm on the reservoir fluid's pressure-temperature diagram. This is the only unique and accurate means of identifying gas condensate reservoirs; any other definition [condensate-gas ratio, C7+ molecular weight (MW) or C7+ API gravity] is specious and ersatz. In these reservoirs, as the pressure drops, vapour and liquid phases result. Capillary pressure causes phase interference which usually reduces gas productivity. A cross-section of interesting topics that show the complexities of gas-condensate reservoir production have been reported in the literature. All of the relevant parameters, if well understood, will lead to more accurate evaluation of the amount of hydrocarbon in place, the rate at which the resource can be produced and the optimization strategies as the reservoir matures. Introduction In this paper, retrograde condensate characterization and properties measurement, explicit relative permeability and two-phase dynamic steady-state measurements are discussed. Not withstanding the very specific nature of this paper in quantifying phase behaviour-fluid flow coupling in the laboratory, it was considered important to provide a short commentary on sampling of gas condensate fluids that form the foundation on which experimental gas condensate testing is built. Extensive treatment of this theme was beyond the scope of the current paper. Retrograde Condensate Sampling The bottomhole flowing pressure (PBHF) must be lower than reservoir pressure to induce flow. If the PBHF is less than dew point pressure then liquids drop out in the porous media around the production well. The gas is much more mobile than the condensate and, therefore, the gas-condensate ratios (GCR) exhibited at surface are commonly higher than that of the reservoir fluid. A further complication of this problem is that the composition of the surface liquid also changes. When the PBHF is above dew point, the MW of the surface liquid is the highest. Figure 1 shows the change in composition incident to decreasing bottomhole pressure.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Slotted liners are used extensively in the majority of steam assisted gravity drainage operations conducted in Western Canada due to their superior mechanical strength and integrity in contrast to other mechanical sand control devices. These liners are required due to the generally poorly or unconsolidated nature of the majority of formations in which SAGD applications are conducted. These liners can have a variety of configurations with varying slot density, slotting patterns, slot apertures and slot internal geometries. The overall objective of a successful slotted liner design is to ensure that the liner allows the maximum production of bitumen and other fluids with a minimum pressure drop, while retaining the majority of the formation sand and preventing infill of the horizontal section of the well with solids and erosion and failure of downhole pumps and surface equipment. This paper describes a detailed lab test protocol which was successfully developed over a number years for the design and evaluation of slot geometry for SAGD applications, describes test procedures used and quantifies some of the major mechanisms discovered that lead to the plugging of slots. It has been found that in addition to grain size of the sand under consideration and slot geometry, that clay content of the formation, flow velocity, wetting phase type and pH play crucial roles in the plugging mechanism of slotted liners. Clay plugging at the top portion of the slots has been found to be the dominant damage mechanism. Introduction Steam assisted gravity drainage (SAGD) is being used extensively in Western Canada and other areas in the world as an effective and economic means for the recovery of heavy oil and bitumen reserves and represents the current primary technology for the exploitation of this large hydrocarbon resource. Key factors in the successful operation of a SAGD process include;Keeping the differential pressure between the lower (production) horizontal well and the upper (injection) well very low to prevent steam coning between the two spatially adjacent wellbores. This allows effective vertical propagation of the steam chamber upwards from the injector, and gravity motivated drainage of the mobilized bitumen down the sides of the steam chamber to the production well. Retaining the formation sand to prevent infill of the producing well (and injection well during periods of possible backflow) with solids which may result in wellbore plugging or mechanical issues with various types of artificial lift systems. Slotted liners have proven to be the sand control device of choice in most SAGD applications to date due to their superior mechanical integrity for long horizontal well completions. Different slotting methods have been developed over the past decade, including (Figure 1);Conventional ‘straight’ cut slots prepared using a single blade plunge into the liner. ‘Keystone’ cut slots prepared using two separate blade plunges to form a single slot, with the blade angle differing between each plunge to form a slot with an ‘aspect’ ratio that has the top of the slot smaller than the base of the slot to aid in the passage of any sand grains/fines that may enter the slot
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.77)
Abstract Previous studies described the theory and application of CO2 miscible hydrocarbon fracturing fluids for gas well stimulation. These fluids are ideally suited to gas reservoirs susceptible to phase trapping resulting from high capillary pressures when water-based fluids are used. Gas reservoirs particularly prone to phase trapping are those with in situ permeability less than 0.1 mD, those with initial water saturations less than what would be expected from normal capillary equilibrium (subnormally water saturated) and those that are under pressured. Such reservoirs represent a growing proportion of the market. This, combined with increased gas prices, creates a strong need for an optimized gas well fracturing fluid system. Hydrocarbon-based fracturing fluids present an ideal solution to phase trapping concerns associated with water-based fluids provided the hydrocarbon fluid can be effectively and quickly removed from the formation after the fracturing treatment. This paper investigates in more depth what constitutes an ideal hydrocarbon-base oil for this application. This involves consideration of many factors including cleanup mechanisms, safety, cost and capability to be gelled and broken. In order to meaningfully evaluate fluid clean up, regained core permeability evaluations must be conducted by accurately duplicating downhole conditions. This paper presents testing methodologies designed to achieve this goal. To illustrate the need for these methodologies, the applicable phase behaviour and fluid displacement mechanisms by which these fluid systems operate are discussed. Topics covered will include:Methane drive fluid recovery mechanism involving the use of CO2 with hydrocarbons and resulting effect on interfacial tension (IFT). Secondary recovery mechanism based on vapour pressure of light hydrocarbons resulting in their being produced back in the gas phase with methane. Application of these concepts to address phase trapping in low-permeability gas reservoirs and how these effects are accentuated in formations that may be subnormally water-saturated, have low reservoir pressure or have low permeability. The need to simulate downhole conditions accurately to properly represent the recovery mechanisms. This includes duplication of temperature, pressure and fluid-loss mechanisms. Duplicating leakoff is the key to representative duplication of phenomena at the fracture face. Compare nitrogen to methane for reference and fluid recoveries and discuss why it is necessary to use methane to obtain proper simulation and modelling of the actual field performance of the fracture fluids. To illustrate fluid performance and demonstrate test methodologies, results of a regain permeability evaluation conducted with the optimum fluid and test methodologies discussed will be presented. It will be shown that in a formation known to be highly sensitive to water-based fluid retention (phase trapping), 100% regain permeability can be achieved at a minimal 140 kPa of applied drawdown pressure. Introduction The use of water-based fracturing fluids in low-permeability reservoirs may result in the loss of effective fracturing half length due to phase trapping effects associated with the retention of a large portion of the introduced water-based fluid in the formation.
- North America > United States > Texas (0.47)
- North America > Canada > Alberta (0.30)
- South America > Brazil > Brazil > South Atlantic Ocean (0.89)
- North America > United States (0.89)
- Asia > Pakistan (0.89)
Abstract Gas production from fractured reservoirs can be very prolific despite the extremely low matrix permeability that may be encountered. In order to quantify production, the interaction between matrix and fracture must be well understood. Knowing the limitations to production is important for operators who drill into very tight matrix reservoirs with varying degrees of natural fractures. This paper describes a laboratory protocol for assessing matrix-fracture interaction and discusses field implications. The well-known pulse decay technique was used for determining matrix-fracture interaction by fitting parameters from a simple numerical model to experimental data. On this basis, the values of four parameters were regressed: fracture permeability, matrix permeability, mass transfer from matrix to fracture and the fraction of the porous media that was fracture. A full discussion of the mathematical approach, optimization technique and experimental protocol is included. It was concluded that the technique has significant non-unique convergence characteristics which make the interpretation of core parameters dependent on the shape of the experimental production history and, therefore, introduces some subjectivity. Results indicate that fracture permeability is relatively insensitive to water saturation whereas matrix permeability and the matrix-fracture transfer function are extremely sensitive to increasing water saturation; the latter two parameters become rate-limiting once early-time fracture production is complete. Background The impetus for this work is experimental. The authors ’ objective was to investigate an experimental approach, known as pulse decay, in order to try and deduce parameters associated with gas flow from fractured porous media and to do so quickly and accurately. This would involve gas flow in the absence of any liquid phase, as well as gas flow in the presence of immobile water saturation. These measurements are important to operators of dry gas fractured reservoirs, especially in the presence of mobile water either naturally occurring or induced during drilling or hydraulic fracturing. Quantifying phase interference effects is routinely done empirically, but the state-of-the-art leak-off tests are time consuming and can be expensive. The authors wanted to investigate the merit of being able to obtain a series of relevant parameters through a simple, inexpensive approach such as pulse decay. Single-phase flow in porous media is well known. For gas flow in porous media, potential areas for obfuscation include gas-solid slip at the wall and turbulence effects. The Klinkenberg protocol is a very effective means of removing the effects of gas-slippage which causes deviation from the assumptions inherent in using the Darcy equation (laminar flow with no flow at the wall). Figure 1 shows a standard Klinkenberg plot done for a sample analyzed in this work. The significance of this correction is that if the pore pressure is high enough, the gas will act more like a liquid and, at low rates, will behave in a laminar manner which requires the development of a quadratic velocity profile in the flow conduits and a no-slip condition at the solid surfaces. Figure 1, with its associated trend-line, shows that by extrapolating to infinite pore pressure where any gas would condense, the effective permeability for this sample is 41.2 mD.
Laboratory Procedures for Optimizing the Recovery from High Temperature Thermal Heavy Oil and Bitumen Recovery Operations
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Ma, T. (Hycal Energy Research Laboratories Ltd.) | Thomas, F.B. (Hycal Energy Research Laboratories Ltd.) | Romanova, U.G. (Hycal Energy Research Laboratories Ltd.)
Abstract Thermal operations such as cyclic steam injection (CSS), steam assisted gravity drainage (SAGD) and steam drive (SD) are used on a worldwide basis to exploit large reserves of heavy oil and bitumen which will comprise the majority of future world oil production in the decades to come. This paper reviews new laboratory protocols that have been developed to aid in the screening of the best reservoir process for exploiting these heavy oil and bitumen reservoirs by thermal means including;Low and high temperature oil property measurements (viscosity, density, formation volume factor, GOR) Aquathermolysis testing to evaluate levels of CO2 and H22S generation that may occur during thermal operations Low and high temperature relative permeability testing to ascertain residual oil saturations and injectivity and productivity for heavy oil applications Hysteresis testing to determine the variance in relative permeability character between injection and production cycles (CSS operations) Testing to evaluate possible permeability reductions due to thermal dissolution, migration or mineral transformation issues Sand control and liner design for optimum performance of horizontal SAGD production wells Examples of the various lab protocols used for these types of testing are described with example datasets provided and comments about how the use of such a testing protocol can aid in the evaluation and optimization of a heavy oil or bitumen thermal stimulation operation. Introduction Current reserves of heavy oil and bitumen are estimated to be in excess of 4000 billion barrels (4 trillion barrels). Although some of this resource is recovered by primary ‘cold’ production methods and surface mining and processing technologies, much of the resource is too deep for conventional mining and extraction and too viscous for primary cold production operations. This leaves various types of thermal enhanced oil recovery operations as the primary method for the extraction of this resource. Thermal recovery operations would include such processes as; Steamflooding (SF) (steam drive process) Cyclic steam stimulation (CSS) or huff and puff steamflooding Steam assisted gravity drainage (SAGD) SAGD variants such as solvent assisted SAGD, etc In-situ combustion (ISC) Currently the vast majority of heavy oil and bitumen recovery operations use the first four techniques. All of these techniques involve the injection of steam into the formation of interest. The high latent heat of condensation and heat capacity of water make it an ideal fluid for the effective transfer of heat to the formation of interest. Generally steam injection occurs at temperatures ranging from 190 °C (low pressure SAGD) to over to 350 °C for some high temperature CSS operations. The primary motivation of such operations is to reduce the in-situ viscosity of the heavy oil or bitumen hence improving the mobility ratio in the reservoir and facilitating the recovery of the heavy hydrocarbon phase.
Abstract The approach to reservoir optimization often begins with the appropriate characterization of the reservoir fluid. Deficiencies in sampling methods may lead to erroneous conclusions regarding the fluids in situ and, therefore, the exploitation strategies considered. Moreover, once sampled, the way in which fluids are recombined is often inadequate. Frequently, bottomhole samples are also problematic and must be analyzed correctly in order to infer the appropriate information about the reservoir system. This paper discusses sampling and recombination methods that improve the representation of reservoir fluids. A number of examples are provided where standard approaches to characterization are inadequate and a protocol of recombination is presented. The benefits of the approach are shown. The impact of characterization is also shown relative to allowable production rates and adherence to regulatory edicts. Introduction Much of the engineering that is involved in the development and exploitation of reservoirs worldwide depends on representative fluid samples. Whether it is the measurement of PVT properties such as density (ρ), formation volume factor (βo), viscosity (μ), interfacial tension (IFT), gas-oil ratio (GOR) or compressibility (c), or the generation of relative permeability relationships or the assessment of enhanced oil recovery (EOR) strategies, each of these endeavors requires a representative reservoir fluid. Although it may seem that the method for the acquisition of a representative reservoir fluid would be straightforward, it is surprising to see the number of fluid characterizations that are incorrect due to an unrepresentative fluid sample. This deficiency then carries through to all of the analyses that are performed and consequently, the results of the engineering may be in error primarily due to the fluid with which the work commenced. Thus, it is important to establish a reliable protocol for the preparation of representative reservoir fluid. Oil and gas reservoir opportunities are distributed amongst a number of different fluid types. The oils may be heavy oil containing very little gas and very heavy, high-density components, more conventional oils, containing components that are easily partitioned into the gas phase or, volatile oils where the difference between the gas phase and the liquid phase is much less pronounced. A typical reservoir fluid phase envelope is shown in Figure 1. While each fluid system will have its own unique phase envelope, Figure 1 should suffice for demonstration. Oil systems exist to the left of the critical point on the phase loop. As one moves to the right of the critical point, the classification of fluid moves to very rich condensates, to retrograde condensates, to wet gas and finally to dry gas. The extremes on either side of the critical point are easy fluids to represent. Heavy oil has almost exclusively methane in the solution gas and C20+ in the liquid. There is very little "gray area" in classifying these fluids. Heavy oils do not normally have characterization difficulties since the solution gas is almost always at least 90% methane; in which case, recombination methods do not significantly impact the recombined oil properties. Dry gas has only gas-phase components and therefore these gases are easy to sample and to represent.
- North America > United States (0.46)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.15)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Dunvegan Field (0.89)
- North America > Canada > Alberta > Doe Field > Altia 102 Doe 10-26-81-13 Well (0.89)
Abstract A number of factors must be considered in the design of miscible displacement processes. This paper discusses a new approach that relates primarily to the laboratory and modelling studies that precede the EOS-based compositional simulation of reservoir performance during the vapourizing/condensing gas drive process. The phase behaviour of a solvent/oil system and determination of miscibility conditions by various special PVT experiments (including the swelling test, RBA, slim tube test, and the continuous multiple-contact experiment) are reviewed along with their importance in building an accurate EOS model to be used in compositional simulation. In addition to experimental PVT data, a special core flow test design for measuring the relative permeabilities to generated fluids by forward/reverse multiple contact experiments is discussed. Based on laboratory PVT and SCAL data, a novel interfacial tension-dependent model of relative permeability and capillary pressure data is presented along with the advantages if incorporated into commercial EOS-based compositional simulation software packages. Introduction Mass transfer between the gas and oil components dominates the displacement characteristics of miscible or near-miscible floods. The overall displacement efficiency of any oil recovery displacement process can be considered conveniently as the product of microscopic and macroscopic displacement efficiencies. In equation form: where E = overall displacement efficiency, ED = microscopic displacement efficiency, and EV = macroscopic (volumetric) displacement efficiency. Microscopic displacement relates to the displacement or mobilization of oil at pore scale. That is, ED is a measure of effectiveness of the displacing fluid in moving (mobilizing) the oil at those places in the rock where the displacing fluid contacts the oil. ED is reflected in the magnitude of the residual oil saturation, Sor, in the regions contacted by the displacing fluid. Macroscopic displacement efficiency relates to the effectiveness of the displacing fluid(s) in contacting the reservoir in a volumetric sense. EV is a measure of how effectively the displacing fluid sweeps out the volume of a reservoir, both areally and vertically, as well as how effectively the displacing fluid moves the displaced oil toward production wells. It is desirable in an Enhanced Oil Recovery (EOR) process that the values of ED and Ev, and consequently E, approach 1. An idealized EOR process would be one in which the displacing fluid removed all oil from the pores contacted by the fluid (Sor →0). Several physical/chemical interactions occur between the displacing fluid and the oil that can lead to efficient microscopic displacement (low Sor). These include miscibility between the fluids, decreasing the interfacial tension (IFT) between the fluids, oil volume expansion, and reducing oil viscosity. The maintenance of a favourable mobility ratio between displaced and displacing fluids also contributes to better microscopic displacement efficiency. EOR processes are thus developed with consideration of these factors. The goal of an acceptable EOR fluid is to maintain favourable interaction(s) as long as possible during the flooding process. In enhanced recovery operations, oil entrapment occurs due to complex interactions between viscous, gravity, and capillary forces.
- Europe (0.46)
- North America > Canada (0.29)
Water and Oil Base Fluid Retention in Low Permeability Porous Media - an Update
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Thomas, F.B. (Hycal Energy Research Laboratories Ltd.) | Schulmeister, B. (Hycal Energy Research Laboratories Ltd.) | Romanova, U.G. (Hycal Energy Research Laboratories Ltd.)
Abstract Phase trapping refers to the temporary or permanent trapping of oil or water based fluids introduced into a porous media during drilling or completion operations which result in a reduction in the effective permeability to the desired producing or injected phase. This problem has emerged in recent years as a major mechanism of formation damage, most notably in low permeability gas producing formations. This paper reviews the current state of the art with respect to new technology which is being used to identify formations that are particularly susceptible to this mode of formation damage, as well as describing some of the most current technology being used to avoid and remove these problems. This includes the use of various types of new non-alcohol based surface tension reducing agents, foamed fluids and other surfactants, transient wettability modifying agents, oil based fluids, as well as CO2 or nitrogen based fracturing technology. The potential advantages of some of these new technologies and where they have the greatest degree of potential application are discussed. Background Phase trapping is a common mechanism of formation damage that can occur in a variety of oil, gas or water bearing formations and can create severe reductions in productivity or injectivity. The problem has been documented in numerous publications in the literature as well as in previous publications by the authors . The basic mechanism of a phase trap refers to either the transient (sometimes referred to as a ‘phase load’) or permanent (phase trap or block) retention of water, oil or sometimes gas based fluids which are generally introduced from an outside source into the formation during drilling and completion operations. There are also situations, such as retrograde condensate gas reservoirs or the depletion of black oil reservoirs, where the creation of potentially permeability reducing near wellbore phase traps may occur through the normal depletion process of the reservoir. Common Types of Phase Traps The most common types of phase traps can be summarized as follows; Gas Producing Formations –Water based phase trapping (caused by water based drilling, completion or kill fluids) –ydrocarbon based phase trapping (caused by hydrocarbon based drilling, completion or kill fluids) or by retrograde condensate liquid dropout in rich gas producing situations Oil Producing Formations –Water based phase trapping (caused by water based drilling, completion or kill fluids) –Gas based phase trapping (caused by gas liberation by sub-bubblepoint production) Water Producing Formations –Hydrocarbon based phase trapping (caused by hydrocarbon based drilling, completion or kill fluids) –Gas based phase trapping (caused by free gas injection) Gas Injection Wells –Water based phase trapping (water of condensation) –Oil based phase trapping (compressor lubricant carryover) Phase trapping is caused by an interaction of capillary pressure and relative permeability phenomena in porous media. A simplified formulation of the capillary pressure equation in porous media can be expressed as; (Equations (1))(Available in full paper)
- North America > Canada > Alberta (0.30)
- North America > United States > Louisiana (0.28)
- North America > United States > West Virginia (0.28)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (7 more...)
Abstract Gas condensate reservoirs may exhibit very poor performance due to serious phase interference effects. Engineer1 describes the Cal Canal field which exhibited exceptional productivity decline incident to liquid drop out. The operator's recommendation for field development was to abandon the reservoir after the reservoir pressure reached the dew point; the forecasted productivity was so poor that most of the hydrocarbon was going to be left unrecovered. Times and gas price have changed but gas condensate production can still be very challenging. Phase behavior, interfacial tension, velocity and pore size distribution all affect how a condensate reservoir will produce. Much can be done in the laboratory to gain insight as to how serious phase interference effects are going to be in the field, long before field problems are encountered. This paper describes experimentation that was done to quantify the impact of pressure depletion on well productivity. The fluid preparation for this project was described in part I of this two part series. The salient findings of this work indicate that:Retrograde condensate resulted in very rapid decrease in gas permeability - 60 and 84% reduction in Krg by the attainment of critical condensate saturation. End-point saturations such as trapped gas and residual condensate saturation are sensitive to the level of interfacial tension (therefore pressure). Critical condensate saturation was much less sensitive to level of IFT (pressure). Two-phase testing as a function of capillary number indicated an effective gas permeability very close to that measured by the explicit relative permeability measurements at saturations just higher than the critical condensate saturation. The condensate and gas permeabilities measured during the gas-phase hysteresis injection did not agree with those measured during the two-phase injection. The two-phase injection approach and the protocol whereby explicit measurement of relative permeability is performed provide a very thorough gas-condensate reservoir data set, which are amenable for use in simulation and reservoir production forecasting. Background When retrograde condensation occurs during pressure decrease the liquid that accumulates fills some of the pores of the porous media. As the liquid increases in saturation the cross-sectional area available for flow may reduce the permeability to gas. The condensate may be mobilized if the draw-down pressure is large enough to overcome capillary pressure; this case results in the liquid having less severe impact on gas production. In some cases, once liquids accumulate, the gas permeability drops quickly and is difficult to restore. Laboratory testing helps the operator to identify which of the two scenarios will be germane to his specific reservoir. If appropriate testing is done some of the uncertainty can be removed from field development (references 3 – 5). To gain an idea of whether a reservoir is going to experience severe liquid phase interference effects one can saturate the core stack, in the laboratory, with equilibrium fluid and then measure regain gas permeability (defined as the percentage of the singlephase permeability that is achieved by flowing equilibrium gas through the core sample) as a function of drawdown pressure at difference absolute pressures.
- North America > United States > California > Kern County (0.54)
- North America > Canada > Alberta (0.48)