Skip Nav Destination
Filter
Filter
Filter
Filter
Filter

Update search

Filter

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

- Title
- Author
- Author Affiliations
- Full Text
- Abstract
- Keyword
- DOI
- ISBN
- EISBN
- ISSN
- EISSN
- Issue
- Volume
- References
- Paper Number

### NARROW

Format

Subjects

Date

Availability

1-15 of 15

Keywords: matrix

Close
**Follow your search**

Access your saved searches in your account

Would you like to receive an alert when new items match your search?

*Close Modal*

Sort by

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 13–17, 1999

Paper Number: PETSOC-99-55

... reservoir, especially if there is clay in the pore throats or if the cementation

**matrix**is carbonaceous or if the reservoir lacks water. The problem is complicated in that many horizontal wells in formations with questionable competency are completed using a slotted liner, making any type of selective...
Abstract

Abstract Various formation damage mechanisms occurring in the Cardium sandstone have been documented. Many of these have been studied in the context of injectivity and other secondary recovery techniques. Recently, increasing attention is being devoted to damage in this formation from a drilling perspective. In the past, drilling induced damage on vertical wells was not a significant concern since most completions involved hydraulic stimulation to enhance production. Now, as horizontal wells and slotted-liner completions become a viable option to operators attempting to increase reserves and production in tighter, less permeable zones, the damage-while-drilling issue becomes extremely important. The objective of this paper is to present and discuss the methodology and testing results used in selecting a drilling fluid to be employed in drilling a horizontal well in the Cardium gas reservoir at Minehead in Central Alberta. Various aspects of both the design of the fluid and its implementation are presented. The initial production results are also included. Introduction Some of the most difficult challenges in fluid design are perpetrated by tight, sub-irreducibly saturated, sandstone gas reservoirs. Although the task is less daunting when these reservoirs are to be drilled underbalanced, diligence is still required. Underbalanced fluid design must focus on both fluid-fluid and fluid-rock compatibility as a contingency against unplanned periods of overbalance or against the occurrence of spontaneous counter-current imbibition 1 . When drilling overbalanced, the fluid design must incorporate one additional dimension - the selection of constituents to create an appropriate filter cake. This is to minimize the loss of whole fluid and mud filtrate into the reservoir. Because the very nature of cake deposition and "bridging" on pore throats and fractures denotes some degree of spurt loss associated invasion, the same design diligence must be applied to the liquid phase of the overbalanced drilling fluid. The solid phase of the fluid - the bridging particles, must be soluble in some fluid when it's time to produce the well. In sandstone reservoirs, even if pore throats are plugged with a portion of insoluble silicate drilled solids, if some soluble product is also present, bridge integrity will often be degraded so that production can begin. The design of the bridging system should also be such that bridging occurs at the first pore throat so that effective "lift off" can also occur. The problem is that the bridging materials available today are either oil soluble, acid-soluble or water-soluble. Often (not always) these solvents are incompatible with the sandstone gas reservoir, especially if there is clay in the pore throats or if the cementation matrix is carbonaceous or if the reservoir lacks water. The problem is complicated in that many horizontal wells in formations with questionable competency are completed using a slotted liner, making any type of selective stimulation almost impossible. Various formation damage mechanisms occurring in the Cardium sandstone have been documented, most of them in the context of production enhancement. These include clay swelling, fines migration, paraffin deposition, scale and bacteria 2 . The design focus for this well centered on swelling clay and another mechanism - phase trapping or water blocking.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-03

... displaced from fractures plus pressure depletion from the

**matrix**. The amount of pressure depletion in the**matrix**is a function of structural relief above the original gas/water contact. Subsequent gas recovery is an imbibition process, which may be very slow. Laboratory work, conducted at the TIPM...
Abstract

Abstract There are numerous examples of tight naturally-fractured gas reservoirs with active water in the foothills of Alberta and Northeastern British Columbia. Examples include the Pincher Creek field in Alberta and the Bucking Horse, Pocketknife, Sikanni and Grassy fields in British Columbia. Recovery factor is typically low from this type of reservoir due to water production. The problem is frequently attributed to coning, but coning may actually play a minor role. In fact, the gas/water contact in the fracture system may be relatively flat. Initial gas recovery comprises gas displaced from fractures plus pressure depletion from the matrix. The amount of pressure depletion in the matrix is a function of structural relief above the original gas/water contact. Subsequent gas recovery is an imbibition process, which may be very slow. Laboratory work, conducted at the TIPM Laboratory on behalf of Husky, demonstrates that water will continue to imbibe into tight matrix rock submerged under water for months. This work implies that the best operating strategy maybe to produce the wells at the highest rates possible until water breakthrough, followed by a shut-in period of perhaps several years to allow gas to re-accumulate. Introduction Significant gas reserves are contained in structured Mississippian-age reservoirs along the eastern foothills of the Rocky Mountains. Equivalent formation names include Livingstone, Turner Valley and Debolt (from southern Alberta through northeastern British Columbia). Matrix permeability in these reservoirs is often insufficient to support commercial production rates. Fortunately, natural-fracturing enhances reservoir permeability, and many foothills gas reservoirs are intensely fractured. Fracturing results from post-depositional thrusting. Prolific wells can be drilled where fracture intensity is greatest, usually along the hinge of a folded structure. In most cases, these reservoirs overlie inactive aquifers. Recovery is simply a function of abandonment pressure, which is in turn a function of minimum economic production rate. Recovery is typically greater than 80 % of original gas-in-place. Aquifer influx can have a devastating influence on recovery, however. Recovery from a reservoir overlying an active aquifer may be less than 20 % of the original gas-in-place. Wells may water-out very abruptly. The problem is often blamed on coning or channeling. Fractures are mistakenly seen as preferential conduits, or "pipelines" into the water leg. With this view, gel treatments, rate restrictions and plug-backs may be implemented to reduce water production; almost always unsuccessful1y. Our premise is that the problem is not caused by coning or channeling. Fractures are planar; not tubular. Even in a vertical fracture, horizontal permeability along the plane of the fracture is approximately equal to vertical permeability. Fractures are not preferential conduits into the water leg. Furthermore, viscosity of gas is typically two orders of magnitude less than viscosity of water, and density of gas at reservoir conditions may be an order of magnitude lower than density of water. Therefore, extremely high pressure gradients would be required to generate a small cone in a permeable fracture system. Rather, in most cases, gas is efficiently displaced from the fractures as the free gas/water contact rises uniformly across the pool.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-33

.... The solutions have not been published previously in the petroleum engineering literature. The solutions are presented for drawdown and buildup tests. The model assumes flow of gas condensate from a tight

**matrix**into permeable natural fractures. The fractures conduct the fluids to the wellbore. It is...
Abstract

Abstract Approximate equations are presented for evaluation of naturally fractured gas condensate reservoirs represented by dual-porosity models in radial systems. The reader is cautioned that this work is in progress. Additional research will help to corroborate and refine these techniques. The solutions have not been published previously in the petroleum engineering literature. The solutions are presented for drawdown and buildup tests. The model assumes flow of gas condensate from a tight matrix into permeable natural fractures. The fractures conduct the fluids to the wellbore. It is preliminary shown that a conventional cross plot of m(p) vs. time on semi logarithmic coordinates results in approximately two parallel straight lines with a separation that is related to the storativity ratio between fractures and matrix. This plot allows determination of key parameters such as absolute permeability, effective permeability's to oil and gas, skin, storativity ratio (ω), fracture porosity (Φ 2 ), average distance between natural fractures (h m ), radius of investigation, and extrapolated pressure (p 1 or p). In addition the method permits generating a liquid saturation profile and a general composition profile around the wellbore at shutin. Introduction Naturally fractured reservoirs have been the object of intensive research during the last few years in the geologic as well as the engineering fields. Transient pressure analysis has received particular attention. Barenblatt and Zheltov (1) and Warren and Root (2) handled naturally fractured reservoirs by assuming pseudo steady-state (restricted) interporosity flow in a model made out of cubes with spaces in between. Flow toward the wellbore was assumed to be radial via the natural fractures. Their work led to the conclusion that a conventional cross plot of pressure vs. log of time should result in two parallel straight lines with a transition period in between. The separation of the two straight liens allowed calculation of the storativity ratio omega, i.e. the fraction of the total storage within the natural fractures. Kazemi (3) used a numerical model of a finite reservoir with a horizontal fracture under the assumption of unsteady state interporosity flow and substantiated Warren and Root's conclusion with respect to the two parallel straight lines. The transition period, however, was different due to the unsteady rather than pseudo steady-state interporosity flow assumption. de Swaan (4) developed a diffusivity equation and analytical solutions to handle the first and last straight lines. His method, however, could not analyze the transition period. Najurieta (5,6) developed analytical solutions of de Swaan's radial diffusivity equation which could handle the transition period as well as the first and last straight lines. Streltsova (7) used a gradient flow model and indicated that the transition period should yield a straight line with a slope equal to ½ the slope of the early and late straight lines. Her examples showing the ½ slopes gave values of storativity ratios approximately equal to 0.37, 0.26, and 0.48. Serra et al. (8) reached the same conclusion with the use of a stratum model for the cases in which the storativity ratio, omega, was smaller than 0.0099. Various type curves have been developed to analyze naturally fractured reservoirs with transient (9,10) and pseudo steady-state (11) interporosity flow.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-79

... Abstract A common question when dealing with tight

**matrix**naturally fracturedreservoirs is - How can we determine if the**matrix**is contributing tohydrocarbon production? One source of information for helping to answer thisquestion is provided by**matrix**and fracture permeabilities determined...
Abstract

Abstract A common question when dealing with tight matrix naturally fracturedreservoirs is - How can we determine if the matrix is contributing tohydrocarbon production? One source of information for helping to answer thisquestion is provided by matrix and fracture permeabilities determined with thePressure-Decay Profile Permeameter (PDPP). The useful range of the tool is from0.001 to 20,0000md. These permeabilities are corrected for overburden conditions and are utilizedto numerically simulate the interaction between matrix and fractures in a core.The procedure involves the following steps: From PDPP measurements create iso-permeability maps of the fracturecore. Discretize the permeabilities using a micro-gridover the core area. Select a ‘production’ cell in the fractures and various observation cellsin the matrix. Simulate the core using reservoir pressure, temperature and fluidproperties. The results indicate if the very low matrix permeability contributes tohydrocarbon production in the naturally fractured reservoir where the core wascut. Introduction There are many naturally fractured reservoir around the world in all kinds oflithologies throughout the various geologic periods. This type of reservoirscontains significant amounts of oil and gas resources. They presents botheconomic opportunities and technical challenges. Inorder to properly exploitnaturally fractured reservoirs, engineers and geologists have developedspecialized techniques and tools to help in their evaluation. The overview of the characteristics of naturally fractured reservoirs andtechniques for their analysis have been the subject of various textbooks 1–5 . In a paper on recent advances in the study of naturallyfractured reservoir, Aguilera 6 summarizes the sources of informationavailable to evaluate naturally fractured reservoirs. In a very simple model, a naturally fractured reservoirs consists of matrixrock with high storage and low permeability. These matrix rock is generally notcapable to sustain commercial production without natural fractures. Thefractures have very low storage capacity but high permeability. Fluid in thematrix can bleed off into the fracture network and then be transported throughthe ractures to the wellbore. An often asked question is whether fluid storedin the tight matrix actually contribute to production. A new technique forpermeabilitymeasurements in cores coupled with numerical microsimulation offerssome answers to this question. This could be combined with a laboratory technique that allows to measureseveral hundred pressure readings in a short span of time to study the responseof cores to pressure disturbances. This laboratory technique allows quick andaccurate determination of matrix and fracture properties as reported by Kamathet al. 7 Fractured core properties A carefully handled core from a naturally fractured reservoir provides valuableinformation on reservoir properties, including whole core porosity andpermeability. From well logs we can estimate porosity in the matrix, andractures. Pressure transient analysis can also add information includingfracture porosity and permeability. All these estimates are related to the bulkproperties of the system. With a new permeability measuring equipment, thepressure-decay profile Permeameter 8–10 , detailed description ofpermeability distribution can be obtained.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-09

... different demulsifier chemical demulsifier variance covariance

**matrix**composition demulsifier performance separation bottle test petroleum society perfonnance principal component analysis upstream oil & gas rock/fluid interaction fluid compatibility optimization production chemistry...
Abstract

Abstract This paper outlines a technique based on 13 C nmr that relates the chemical structure of the demulsifier chemical to demulsification performance. Principal component analysis methods were used to handle the extensive data generated from nmr and bottle test results. Over one hundred demulsifiers grouped or clustered into only a few distinctly different chemical groups as characterized by the nmr. The similar chemical types fwd similar demulsification performance which means that demulsifier evaluations can be made on the basis of demulsifier chemistry and that only a few of the distinctly different ones need to be tested before optimization can begin. Since the nmr chemical clwracterization takes only a fraction of the time of a bottle test it is now possible to more rapidly focus on optimization of demulsifier dosage. The method is useful for operators as a quality control evaluation of the demulsifier chemicals they use and for the suppliers as a way to significantly decrease the number of demulsifiers that are evaluated in the field before work begins on optimization. Introduction Chemical demulsification is commonly used to separate water from heavy oils in order to produce a fluid suitable for pipelining (typically less than 0.5 percent solids and water). A wide range of chemical demulsifier are available in order to effect this separation. In principle, a complete chemical and physical characterization of both the demulsifier and the emulsion to be separated would allow one to develop a fundamental understanding of the demulsification mechanism and therefore to optimize the demulsifier selection or allowsynthesis of tailored demulsifiers for separation of particular emulsions. In practice, this is not possible because of the wide range of factors that can affect demulsifier performance. Aside from demulsifier chemistry, factors such as oil type, the presence and wettability of solids, oil viscosity and the size distribution of the dispersed water phase can all influence demulsifier effectiveness. Over 121 different demulsifiers (or demulsifier bases) and six different produced oil samples were evaluated. Clearly, it would be prohibitive to develop detailed chemical and physical analyses of such a large number of demulsifiers and as indicated above, such detailed analyses of the demulsifiers may not completely account for their performances on different oil emulsion samples. However, by elating performance on a given emulsion with chemical composition, it would be possible to rapidly optimise demulsifier selection by testing selected members of chemically distinct groups and doing more detailed bottle tests on members of the groups that showed the best results. Principal component analysis (PCA) is one method that allows one to relatively quickly develop correlations between similar members of large data sets. These groupings or clusters of members of data sets are based on an analysis of the variances (in the measured data set) amongst them and precludes the need for extensive fundamental analyses of each of the members. Principal Component Analysis may be performed on data sets where the samples are described by a variety of independent or dependent variables.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-16

... interporosity flow regime. The results have shown that the radius of investigation in such reservoirs starts increasing in the fracture network proportional to the square root of the fracture conductivity. When the

**matrix**contribution to the flow of fluids starts the rate of advance of the radius decreases...
Abstract

Abstract The reservoir parameters obtained from any transient pressure analysis, reflect average values of the characteristics of the area around the well that has experienced a pressure disturbance due to the change of flow rate at the wellbore. This area is described by an associated radius called the radius of investigation. In the authors&apos; knowledge, no work has been done to examine this radius in fractured or dual porosity reservoirs. This paper describes a new equation for evaluation of the radius of investigation for well tests in such reservoirs under pseudosteady state interporosity flow regime. The results have shown that the radius of investigation in such reservoirs starts increasing in the fracture network proportional to the square root of the fracture conductivity. When the matrix contribution to the flow of fluids starts the rate of advance of the radius decreases until its magnitude reaches a maximum value and remains constant until the total system stabilizes. After this time the radius increases again with a lower rate dependent now on the total system conductivity. Introduction The radius of investigation also called the radius of influence or radius of drainage is defined in many ways by several authors 1,2,3.4.5,6 . In most definitions this radius determines a circular system with a pseudo-steady state pressure istribution around the wellbore, and takes the form as follows: Equation (1) Available In Full Paper where A is a constant and r inv is the radius of investigation. If the start of semi-steady state flow for a homogeneous and symmetrical bounded cylindrical reservoir at a time t De of 0.3 is used, and the parameters are defined in oil field units where, r inv is in feet, t is the time of flowing for a drawdown test or the time of shut-in when Δtp for a buildup test in hrs., K is the formation permeability in mds, φ is the reservoir porosity in fraction and c is the total system compressibility in psi −1 , the constant A becomes 0.029. Odeh and Nabor 7 , by using an RC analyzer obtained A to be 0.0257, and Kazemi 8 from the numerical finite difference solution obtained it to be 0.035. Hurst et al 3 , Van Poolen 5 and Slider 9 separately used the concept of unsteady state radial flow to find out when to switch from infinite acting solution to finite solution of the homogeneous diffusivity equation. By taking the derivative of the difference between the above solutions with respect to time and putting it equal to zero the flowing equation for radius of investigation will be obtained: Equation (2) Available In Full Paper Matthews and Russell 10 picked a time t De of 0.25 intermediate to the two times corresponding to the end of infinite acting and the start of semi-steady state, and obtained the same Eq.2. Muskat 1 , Chatas 11 and Craft and Hawkins 12 by equating the volume of the fluid produced to the expansion of the fluid contained in the drainage area and by considering steady state conditions also obtained the same Eq. 2 for r inv . Note: The paper is missing text between pages 4 and 5. This is the version included in the proceedings. It is priced free of charge.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, April 20–23, 1991

Paper Number: PETSOC-91-53

... Abstract An analysis of the response of naturally fractured reservoirs to thermal recovery processes is presented, utilizing a suite of dual continuum reservoir simulation models (dual porosity, multiple interacting continua, vertical

**matrix**refinement and dual permeability). The effects of...
Abstract

Abstract An analysis of the response of naturally fractured reservoirs to thermal recovery processes is presented, utilizing a suite of dual continuum reservoir simulation models (dual porosity, multiple interacting continua, vertical matrix refinement and dual permeability). The effects of the different models as well a, many fracture and matrix properties on aspects of stearn cycling, steam drive and gravity drainage processes are discussed in some detail. While some factors are consistent with the isothermal response of naturally fractured reservoirs (in particular fracture spacing and the primary effect of matrix permeability), thermal phase behavior and heat flow effects in these reservoirs impart significantly different more complex behavior. Most of the naturally fractured reservoirs which are produced by using thermal processes contain very low mobility oil and therefore heat conduction plays a very important role at the initial stages of production. With increasing oil mobility, convective gravity and capillary forces lake over if the matrix permeability is fairly high or the reservoir is fractured extensively. During a production cycle in a stearn stimulation process, heal is conducted from matrix rock to fracture fluid which can increase the fluid's energy tremendously. Depending on the fracture fluid (water/oil) volatility, the additional energy can cause different phase behavior responses. Introduction Fractured reservoirs occur worldwide in the Middle East, Iran, Iraq, France, USA, Venezuela, Canada (Saidi (1987), van Golf-Racht, (1982)), and hold extensive hydrocarbon reserves. The presence of a large number of fractures throughout the reservoir provides extended area, of high permeability, where the fluid flows more easily. However, the productivity of these reservoirs depends on the porosity and permeability of the matrix, which stores most of the fluids in place. Production will cease in reservoirs with very Light matrix rock after the fracture network is depleted, because fluids arc not able to flow at reasonable rates from the matrix to the fracture. Reservoirs with fair matrix permeability will sustain production, because fluids from the matrix will flow into and replenish the fractures. Although fractured reservoirs have been known and produced for decades, a wide variety of production levels and reservoir responses have been observed. This, in turn has given impetus to more recent indepth analysis (both experimental and theoretical) of the underlying mechanisms. The utility of reservoir simulation models in decoupling and quantifying contributing factors has been recognized. Initially, the behavior of fractured reservoirs was simulated by "single porosity" models with two different approaches: Fraclure and matrix properties were averaged. With this approach the oil recovery is usually overpredicted, (Chen, et al (1987), Dean and Lo (1986)) especially in situations where the fracture spacing is large. Fracture and matrix were represented by separate grid blocks. This case has two major drawbacks for field simulation studies: a very large number of grid blocks is needed to represent the whole reservoir numerical difficulties arise due to great differences between fracture and matrix properties Later, Barenblalt, et al (1960) and Warren and Root (1963) introduced a simple dual continuum concept (the dual porosity model) for single phase flow.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 9–12, 1990

Paper Number: PETSOC-90-118

... Abstract The recovery of gas from coal beds is a two-step process. First, the gas diffuses through the

**matrix**then, secondly, it flows through the cleats to the wellbore. If the release of gas from the**matrix**to the cleats is very rapid compared to the flow of gas and water in the cleats, the...
Abstract

Abstract The recovery of gas from coal beds is a two-step process. First, the gas diffuses through the matrix then, secondly, it flows through the cleats to the wellbore. If the release of gas from the matrix to the cleats is very rapid compared to the flow of gas and water in the cleats, the desorption kinetics are relatively unimportant in modeling coal bed methane production. If the coal is well cleated, it can be assumed for engineering purposes that the gas desorbs instantaneously from the matrix to the cleat when the pressure in the cleat decreases. This assumption allows the adsorption of gas on the surface of the coal to be modeled as gas dissolved in an immobile oil. Conventional reservoir simulators can then be used for coal bed methane modeling purposes. The solution gas-oil ratio of this immobile "pseudo" oil is calculated from the Langmuir adsorption isotherm constants and coal bed properties. Additional modest modifications are required in the data describing the porosity and gas-water relative permeability curves to account for the presence of the "pseudo" oil. No code modification is required. This concept has been used with several different simulators to successfully model both single well and 3-D, multiwell coal bed methane problems. A coal well simulation using this method and COMETPC, a simulator developed by ICF-Lewin, are compared. References and illustrations at end of paper. Introduction Coal beds are naturally fractured, low pressure, water saturated gas reservoirs. While some free gas may exist in a coal deposit, the majority of the gas is absorbed on the surface of the coal matrix. When water is removed from the natural fractures of the coal, the pressure is reduced and gas is released from the matrix into the fractures. Once in the fractures, the gas flows to the wellbore. Thus coal degasification is a two-step process: desorption of gas from the coat matrix followed by flow through the fractures. The slower of these two processes will control the rate of gas production from a coal. For engineering purposes, gas production can be approximated by mathematics which focus on the dominant process. If the rate of gas desorption from the matrix is very slow compared to the rate of fluid transport in the fractures, diffusion equations need to be incorporated into a conventional simulator to describe gas production. If the release of gas from the matrix is very rapid compared to the time scale of fluid flow in the cleats, gas production can be modeled by Darcy's law only. Previous Studies Of Characteristic Diffusion Times Times required for various coals to desorbs gas have been reported in the literature. In developing the Direct Method for determination of coal bed gas content, Bertard, et. al. 1 measured methane desorption from several different European coals and found that different coals released methane at different rates. Desorption of 90% of the gas required between 34 and 90 hours. The desorption rate was round to increase with temperature, thus the in-situ desorption rate is faster than that measured at ambient temperatures.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 9–12, 1990

Paper Number: PETSOC-90-119

... Abstract The key mechanisms of two-phase gas-water flow through coal beds as utilized in a new three-dimensional finite-difference simulator, COMETPC 3-D, are presented. The theory for gas transport through coal

**matrix**, transfer of gas from**matrix**to fracture, and the adsorption isotherm...
Abstract

Abstract The key mechanisms of two-phase gas-water flow through coal beds as utilized in a new three-dimensional finite-difference simulator, COMETPC 3-D, are presented. The theory for gas transport through coal matrix, transfer of gas from matrix to fracture, and the adsorption isotherm boundary condition at the matrix-fracture interface is described. Several unique features of coal beds which can affect gas productivity including stress-sensitive permeability, matrix shrinkage compressibility, and gas re-adsorption are incorporated in the model. Applications to history matching production data from coal bed methane wells, studying changes in flow' behavior in coals with gas desorption, and modeling horizontal wells are presented. Introduction Simulation of coal bed methane reservoirs is a more complex and data intensive process than for conventional gas reservoirs. This is because the primary means of gas storage in coal beds is byadsorption of methane molecules on coal surfaces. When a coal bed is subjected to pressure drawdown, the desorbed gas must move by diffusion through the extremely low permeability coal matrix in order to reach the natural fracture (cleat) system. Once in the cleats, which normally have a high permeability relative to the matrix, gas and formation water flow according to Darcy's law. A number of approaches have been taken to simulate these complex mechanisms in coal. The methods vary from the early work of Price and Abdalla 1 on equilibrium sorption models for degassing coal mines, to the unsteady state models of Ancell et al 2 and Kolesar et al 3 . An excellent review of numerical simulation work to date pertaining to coal bed methane has been given recently by King and Ertekin 4 . The fully 3-D, multi-well model described here is based on the non-equilibrium, pseudo steady-state formulation discussed by King et al 5 , and as such is an extension of an earlier 2-D models 6 . The 3-D model was developed in conjunction with the Gas Research Institute (GRI) and a thirteen company industry consortium. It has been validated against other industry simulators, and used in numerous coal bed reservoir studies, most notably in the Black Warrior and San Juan Basins. Theory Of Flow Through Coal beds Coal cleat-matrix represents a well-defined dual porosity system as described by Warren and Root 7 . The face and butt cleats constitute a well developed set of approximately orthogonal vertical natural fractures, shown as a highly idealized schematic in Fig. 1. The coal matrix consists of a micro porous system through which gas diffuses to the fractures. Desorption of methane is described by a Langmuir 8 isotherm, which relates the coal cleat pressure, P, to the equilibrium matrix gas concentration, C(P), according to Equation (1) (Available In Full Paper) Where V L is the maximum amount of gas that can be adsorbed, and P L , a characteristic pressure, is a measure of the residence time for a gas molecule on the surface. Both V L and P L may be determined from laboratory adsorption isotherm measurements. Eq. 1 provides the necessary boundary condition between cleats and the coal matrix.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, January 1, 1989

Paper Number: PETSOC-89-40-42

... were designed with sufficiently high density and very good fluid loss control. This paper analyses the problem of gas migration, presenting the mechanisms for its occurrence within the cement

**matrix**or at the cement to formation interface. A description is then given of a successful technique of...
Abstract

Abstract One major problem for Operators when cementing casing through gas zones has been the effect of gas channeling, or migration, in the cemented annulus. This problem has been found to be definitely more difficult to solve in shallow, low temperature wells, even though the cement slurries were designed with sufficiently high density and very good fluid loss control. This paper analyses the problem of gas migration, presenting the mechanisms for its occurrence within the cement matrix or at the cement to formation interface. A description is then given of a successful technique of combining a special cement system with good cementing practices, so as to provide excellent long term zonal isolation across problematic gas zones. This technique is based firstly on the proper displacement of the drilling mud through good cementing practices, and then secondly on the placement in the annulus of a well dispersed, non-gelling impermeable cement. The key of this system is a specially stabilized latex additive which, through its film forming properties, reduces to zero the gas permeability in the cement slurry when the gas attempts to permeate under differential pressure. Field case histories of this technique are presented, illustrating the versatility of the system in solving gas migration problems in extreme situations. Introduction During and after primary cementing, by far the most critical problem is to prevent the percolation of gas through the cemented annulus that leads to the development or wide and very conductive channels in the cement sheath. This gas channeling often occurs soon after the cement is in place and, once established, has proved to be extremely difficult and costly to repair. This paper is then intended to identify the causes of such a phenomenon and to present a cementing technique which has proved to be very efficient in fields where gas migration was recognized lo be a major problem. GAS MIGRATION - THE PROBLEM If there is, after a given period a differential pressure favoring gas migration, it is dear that gas may follow one or both of two basically different paths: within the cement structure (called matrix channeling) occurring anytime when the cement behaves as a liquid or a permeable solid: at the cement and formation or/and casing interface (called interfacial channeling) occurring once the cement has hardened and becomes an impermeable solid. Matrix channeling Density control; As long as the cement behaves as a true liquid, gas is able to channel in the annulus only if gas pressure is higher than the full (mud. washes, spacers and cement) hydrostatic pressure exerted on the formation Then, first, the density of fluids placed in the gas well must be properly designed by hand or with a free fall (U tubing) computer simulator so that, at any time and at any point in the well, the hydrostatic pressure exerted by the column of fluids (in static condition) plus friction pressure (during placement) stays between the pore and the fracturing pressure of the formation.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–15, 1988

Paper Number: PETSOC-88-39-02

...

**matrix**symbolically, based on the structural patterns generated by D4 ordering. The reduced systemoccupies a single Quadrant of the original**matrix**, requiring fewer floatingpoint operations to solve. Execution time and memory requirements are compared between the Symbolic D4method and band algorithm...
Abstract

Abstract A cost-limiting factor of numerical reservoir simulation is the execution timespent on solving large systems of equations.The Symbolic D4 method is a newdirect solver which uses less memory and is significantly faster than otherdirect methods. This method decomposes the coefficient matrix symbolically, based on the structural patterns generated by D4 ordering. The reduced systemoccupies a single Quadrant of the original matrix, requiring fewer floatingpoint operations to solve. Execution time and memory requirements are compared between the Symbolic D4method and band algorithm using PCSIM Version 1.0, a three-phase, three-dimensional black oil simulator for the IBM PC. One, two andthree-dimensional applications are investigated_ It is shown that the Symbolic D4 method is many times faster than the band algorithm, while using a fractionof the memory. Performance also improves with increasing grid Size, making the Symbolic D4 method ideally suited for multidimensional simulation on smallercomputers with memory and/or speed limitations. Larger grids can be addressedand results obtained more rapidly. Introduction Differential flow equations, typically used for mass and energy balances inreservoir Simulation, are spatially discretized on a reservoir grid. Spatialvariables, such as pressure, temperature and saturation, Will generally have adifferent numerical value at each element (i, j, k) in the three-dimensionalreservoir grid (NX, NY, NZ). Finite difference equations (FDE's) relate spatialvariables at each grid element (i, j, k) to the values in adjacentelements. Finite difference equations with the block standard form Equations 1(available in full paper) Are commonly used in reservoir simulation. The dependent variables, X, arealgebraicly related to their neighbouring values using the block differencecertificients, Z, B. D, E, F. H, Sand Q. An FDE set at each element (i, j, k)yields a system of linear equations, one set for each of the N unknowns, Equations 2 & 3(available in full paper) Conventional solution algorithms are based on a certifficient matrix A 1 which has a banded structure based an a natural ordering of thegrid elements (Figure 1a). Numbering the grid elements consecutively alongalternate diagonasis (1) , will partition the coefficient matrix Intowell defined quadrants (Figure 1b) The (diagonal quadrants are strictly blockdiagonal. The alternate diagonal, or D4 ordering gives rise to a precise matrixstructure which allows partial symbolic decomposition (2) into upperand lower block triangular matrices. Forward and backward substitutions canthen be used to obtain the solution. Theory A. D4 mapping is defined for the natural index of each grid element, ijk, Equations 4(available in full paper) to its corresponding D4 Index. The inverse D4 mapping follows directly. Equations 5 & 6(available in full paper) The equivalent D4 ordered block difference system (2). has the vectorquantities, Equations 7(available in full paper) and a corresponding coefficient matrix with nonzero block elements, Equations 8(available in full paper) LU decomposition of A Into upper and lower block triangular matrices, Equations 9(available in full paper) Will have the general forms illustrated In Figure 2.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–15, 1988

Paper Number: PETSOC-88-39-64

... type. Parts of the water can be stored in the

**matrix**and parts in the system of natural fractures. The aquifer might be limited by an impermeable lithology and thus the oil reservoir and the aquifer can be contained within a closed volumetric unit. In other cases, the aquifer might outcrop at one or...
Abstract

Abstract The diffusivity equation for naturally fractured reservoirs represented by dual-porosity systems has been solved as a function of dimensionless times (t 0 ) and dimensionless water influx (Q (t))for various ratios of aquifer to reservoir size. Results are presented in a similar format to the one used by Van Everdingen and Hurst, 1 in their classic solution for conventional single-porosity reservoirs. Unrestricted (transient) and restricted (pseudo steady) interporosity flow have been taken into account. Results indicate that the use of conventional water influx equations in naturally fractured reservoirs can lead to significant errors. Introduction Some naturally fractured reservoirs are partially or totally bounded in their peripheries by large or small bodies of water known as aquifers. The aquifers might contain natural fractures of a tectonic, regional or contractional type. Parts of the water can be stored in the matrix and parts in the system of natural fractures. The aquifer might be limited by an impermeable lithology and thus the oil reservoir and the aquifer can be contained within a closed volumetric unit. In other cases, the aquifer might outcrop at one or more places and is replenished by surface waters. Yet in other cases the aquifer might rise structurally over the hydrocarbon reservoir giving origin to artesian flow of water towards the reservoir. Craft and Hawkins 2 have presented a lucid treatment of water influx in conventional single-porosity reservoirs, based on Laplace transformation solutions published by van Everdingen and Hurst. 1 In their approach the aquifer is considered as an independent unit which encroaches water in the hydrocarbon reservoir as a response to time variations in the average pressure along the water-hydrocarbon contact. This paper presents a similar approach for analyzing water influx from a naturally fractured aquifer. Values of dimensionless water influx Q (t), have been calculated as a function of dimensionless time (t D ) for the case of infinite aquifers and for various ratios of aquifer to hydrocarbon reservoir size. The solutions presented in this paper have been validated by running calculations using a value of omega equal to 1.0 and comparing results against those published by Van Everdinqen and Hurst. 1 Comparisons are highly satisfactory. THEORY Fig. 1 shows a schematic of the idealized model considered in this study. The aquifer is naturally fractures. The hydrocarbon reservoir might or might not contain natural fractures. The reservoir and the aquifer are horizontal and have radial configuration. Water movement towards the reservoir occurs only through fractures in the aquifer. The upper and lower boundaries are impermeable. Fracture permeability is independent of pressure and exceeds the matrix permeability by at least one order of magnitude. The storage capacity of the matrix is large compared with the storage capacity of the fractures. The matrix blocks are uniformly distributed throughout the aquifer. The matrix and fracture compressibilities can be equal or they can be different provided that pon decompression they do not affect fluid flow in a significant way. Single phase flow of a slightly compressible fluid is modelled with Darcy's law. Viscosity is constant. Density of fluids in matrix and fractures is equal.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, May 2–5, 1981

Paper Number: PETSOC-81-32-22

... Abstract A naturally fractured reservoir consists of two distinct regions, each one with its own porosity and permeability. Data obtained from core analysis such as permeability, porosity, relative permeability curves and capillary pressures are representative of only the

**matrix**(or primary...
Abstract

Abstract A naturally fractured reservoir consists of two distinct regions, each one with its own porosity and permeability. Data obtained from core analysis such as permeability, porosity, relative permeability curves and capillary pressures are representative of only the matrix (or primary porosity) system. Consequently, these data should not be used in material balances or numerical simulators without proper corrections to account for the presence of fractures. Furthermore, as reservoir pressure declines, there is a reduction in porosity and permeability due to closing of the fractures. This effect produces a continuous change in the relative perm abilities of the composite system. This paper presents techniques to generate relative permeability curves for a double-porosity system at initial and subsequent reservoir pressures. The techniques are based on integrated studies of core, log and well testing data, and net overburden pressures. Introduction In many cases, data obtained from core analysis such as permeability, porosity, relative permeability characteristics and capillary pressure curves are used in the evaluation of naturally fractured reservoirs without accounting properly for the presence of fractures. The data obtained from cores apply in nearly all cases to the matrix (primary porosity) system only. Consequently, the use or these data without proper corrections can lead to serious errors when forecasting performance of naturally fractured reservoirs. Experience indicates that the gas-oil ratio increases faster in fractured than in non-fractured reservoirs. This occurs because the critical gas saturation within the fracture network is very small and in many cases approaches zero. Furthermore this occurs because the relative permeability curve to gas in the fractured reservoir is steeper than in the non-fractured reservoir. An example 1 of a significant increase in gas-oil ratio below the bubble point is provided by the Driver field (Spraberry Sand) of Texas (Fig. 1). Note that the GOR has increased to about 12,000 scf/STB when the oil recovery was less than 7 percent. An important increase over the initial gas in solution had been already noticed at recoveries as low as 3 and 4 percent. To avoid potential economic fiascos due to optimistic forecasts of naturally fractured reservoirs, it is necessary to work with relative permeability curves representative of the composite system. In some cases composite relative permeability curves which remain constant over the life of the reservoir have been used. 2,3 In other situations, constant sets of relative permeabilities for each fractures and matrix have been utilized. 4 It appears, however, that in some reservoirs there is a tendency for the fractures to close as the reservoir is depleted because of an increase in the net overburden pressure. In these cases there is a continuous change in the relative permeability curves. This paper presents methods to generate such relative permeability curves. The techniques are based on integrated studies of core, log and well testing data, and net overburden pressures. These techniques are not claimed to be perfect, however, they are giving encouraging results. THEORETICAL AND EXPERIMENTAL BACKGROUND Experience indicates that, in some cases, a fracture system can be represented by a bundle of tubes. 5

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, May 24–27, 1980

Paper Number: PETSOC-80-31-34

... Abstract In the reaction of formation rock with acid, as in a

**matrix**acidizing treatment, varying quantities of insoluble fines are released or otherwise dislocated by the flow. Normal reservoir flow can also cause the breaking or dislodging of fragile clays and minerals present in the pore...
Abstract

Abstract In the reaction of formation rock with acid, as in a matrix acidizing treatment, varying quantities of insoluble fines are released or otherwise dislocated by the flow. Normal reservoir flow can also cause the breaking or dislodging of fragile clays and minerals present in the pore spaces. U allowed to settle and accumulate, these fines can plug pore throats. The addition of a silt-suspending additive to the acid used for a matrix acidizing treatment will help prevent this accumulation by keeping the fines distributed in the fluid. This prevents the plugging that can occur while removing these fines from the formation. The part silt-suspending additives play in both preventing and removing formation damage may be broken down into three areas of discussion: causes of production declines, factors to consider in designing the proper acidizing treatment, and perhaps most important, laboratory results obtained when testing silt-suspending additives. These test results include measurements of suspending power and surface tension, with emphasis on the analysis of three formation cores and their response to treatment with the silt-suspending acid mixture. The cores under evaluation include: Basal Colorado Formation – Cessford field(915.7-915.9 meters). Manville Formation – Cessford field (1010.1-1010.3 meters). Glauconite Formation – Murphy field (1010.1-1046.0 meters). Introduction Matrix acidizing sandstone for the removal of silts and fines is a commonly practiced completion and workover treatment. 1–3 In the removal of these solids, surfactants and acid blends have been tested in many areas. Because no area is exactly the same as another, no single additive is universally applicable. By selectively blending surfactants, it is possible to obtain a mixture with more universal properties. During the dissolution of formation rock by hydrochloric acid or hydrofluoric acid treatments, the majority of the producing formations release some fines. Insoluble materials found in formations, such as clays, feldspars and silicas, are released in large amounts. These solids must be removed to obtain any conductivity in etched channels or pores. DECLINES IN PRODUCTION A decline in production can be the result of one or a combination of factors. An obvious reason for production drop-off is a depleted reservoir. Secondly, however, the problem may be reduced conductivity in the area immediately adjacent to the wellbore. This reduction in conductivity or permeability can occur in either the formation matrix or in a proppant packed fracture. In either case, permeability reduction, whether due to drilling fluids, silts and fines migration, or the precipitation of insoluble compounds, is a result of flow restrictions. The impact of this permeability loss on well production is more severe as it nears the wellbore. In this situation, the formation matrix acts as a filtering medium. The following procedure was used in the analysis of the selected acid blends. A total of 10 acid solutions were prepared. Five of the solutions contained the test additives including the suspending agents the other five solutions were mixed as corresponding references, containing all the same additives except the suspending agent.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 10–12, 1975

Paper Number: PETSOC-75-18

... Abstract

**Matrix**acidization has long been an important completion and stimulation tool. This paper discusses underlying concepts, treatment techniques, and results of acidizing both carbonates and sandstones. Introduction Acidization has been a useful process in initiating and promoting...
Abstract

Abstract Matrix acidization has long been an important completion and stimulation tool. This paper discusses underlying concepts, treatment techniques, and results of acidizing both carbonates and sandstones. Introduction Acidization has been a useful process in initiating and promoting petroleum production for many years. Without completing a history of the process, a summary of developments are in order to bring us to the present day. Originally, acid was dumped or bailed into place and allowed to sit until it had done its work. Development of high pressure pumps allowed displacement of acid to formation and slow squeezes into the formation. Encouraged by the success of hydrochloric on carbonate formations, researchers tried hydrofluoric acid on sandstone reservoirs, but until recently HF had not been as successful as predicted or hoped. Recent research has concentrated on two areas: sandstone acidizing, its techniques problems criteria 4,5,6; and with acid fracturing, the parameters, design, and prediction of results 1,2,3. In the leap of technology to acid fracturing, matrix treatment of carbonates has been severely overlooked. The purpose of the presentpaper is to bring together discussions of matrix carbonate acidizing, with summaries of sandstone acidizing, post treatmentevaluation and examples. Any discussion of matrix processes should be prefaced by a definition of the adjective matrix. We have confined the meaning to those processes which take place within the pores of the rock and which act on that portion of the rock surrounding the pores. Although fracturing affects the rock matrix (by cleavage and dissolution), it is not considered a matrix process. We, therefore, believe that the important part of the definition is the confinement to pore spaces. The large increases predicted for and expected from fracturing have tended to eliminate matrix acidizing other than as a prelude to fracture treatments. There are, however, many other applications for matrix treatments which will increase productive capacity and efficiency. Situations in which to consider matrix acidizing are: presence of nearby gas cap or acquifer; surface or well constraints preventing fracturing; allowable or productive limitations on investment recovery, poor fracturing success; cost constraints on treatment performed. In the main, these are self explanatory, but a bit of elaboration on item (4) is in order. There are many cases where matrix acidizing can be successful even though fracturing has failed. Sandstones soft enough, that all flow capacity is lost through embedment, or hard enough that proppant has crushed, blocking flow channels; or carbonates that etch so uniformly or leave such weak insolubles that the fracture closes on release of treating pressure will respond to matrix techniques. Treatment Mechanics It is very important that the treatment be confined to the pore spaces. Particularly this is true in the initial stages of the treatment.