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Collaborating Authors
SPE Annual Technical Conference and Exhibition
SPE Member Abstract Three methods are widely accepted for evaluation of the wetting properties of a rock/fluid system:The Amott test, The USBM-test and Contact angle measurements. In this work the Amott test and the USBM-test have been run in a combination procedure on reservoir rock samples, while contact angle procedure on reservoir rock samples, while contact angle measurements were performed on quartz surfaces. Nine core plugs from two reservoirs in the North Sea were tested in native state and then cleaned and retested. The experiments were run at 80 degrees with separator crude oil and synthetic formation water. The paper includes a detailed analysis of the experimental results and the experiences gained with respect to wettability testing, apparatus and procedures, core plug preparation techniques, procedures, core plug preparation techniques, cleaning methods and measurement reproducibility of wettability tests. The results from the wettability testing show that the Amott index and USBM-index coincide very well, and that a test procedure combining Amott and USBM is superior to single tests. The results also show that the cleaning procedure used in this work did not render the plugs completely water wet. This could be due to content of oil wetted minerals or remaining organic matter. The results from the contact angle measurements on clean quartz show that the system is more water wet than indicated by the Amott/USBM test. This contact angle behavior confirms the interpretations based on the cleaning and wettability tests. Introduction Capillary pressures, wettability and interfacial properties are important parameters in reservoir properties are important parameters in reservoir engineering. The distribution of fluids within the porous medium is governed by the fluid-fluid and porous medium is governed by the fluid-fluid and fluid-rock interaction parameters. This distribution in turn affects the displacement of the reservoir fluids. To properly predict reservoir behavior under normal production or when the reservoir is planned for secondary production, wettability and planned for secondary production, wettability and capillary properties enter as key parameters. Wettability, however, is not easy to quantify, and therefore numerous methods for wettability measurements have been proposed. All methods have advantages and limitations and an exhaustive review pager on wettability measurements are given by Anderson. In this work the wettability has been determined by contact angle measurements, Amott-tests and capillary pressure curves. The contact angles were measured with formation fluids on a prepared flat quartz surface. The Amott method combines imbibition and forced displacement to measure the average wettability of the core. Crude oil and synthetic formation water were used and initial water saturation was established in the cores before the Amotttest started. The third quantitative test that is used to measure the wettability is the USBM test developed by Donaldson et al. The test compares the work necessary for one fluid to displace the other. Because of the favourable free-energy change, the work required for the wetting fluid to displace the non-wetting fluid from the core is less than the work required for the opposite displacement. The required work is proportional to the area under the capillary pressure curve. In this project, the USBM test was run in combination with the project, the USBM test was run in combination with the Amott-test as described by Sharma and Wunderlich. The procedure is shown in Fig. 1, and from the oil drive and water drive curves, a USBM-wettability index is calculated according to the equation: where A1 is the area under the oil drive curve and A2 is the area under the brine drive curve. P. 199
- North America > United States (1.00)
- Europe > Norway > North Sea (0.71)
- Europe > United Kingdom > North Sea (0.61)
- (2 more...)
- Geology > Geological Subdiscipline (0.94)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (0.65)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.96)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
SPE Members Abstract The paper presents an analysis of nonlinear Darcy flow of gas in reservoirs. The equations employed in the analysis are derived from an integration of the fundamental equations describing the flow of real gases in homogeneous porous media. The equations are derived in terms of squares of pressure for radial steady and pseudo steady flow systems. pseudo steady flow systems. The analysis indicates that the squared-gradient nonlinearity present in the gas flow differential equation results in a present in the gas flow differential equation results in a pressure drop and rate relationship symptomatic of non-Darcy flow. pressure drop and rate relationship symptomatic of non-Darcy flow. The magnitude of the nonlinear contribution to pressure drop is similar to that computed on the basis of non-Darcy theory. This raises the possibility that observed nonlinearities may not be due to non-Darcy effects but merely a result of fluid property variations. The implication of the findings to the simulation of gas wells is also discussed. The results suggest that for a typical radial grid system with fine grids near the well, it may be unnecessary and incorrect to include additional terms to account for deviations from Darcy flow. In large and rectangular grids however, nonlinear terms are required for correct representation. These additional terms are shown to relate to grid size and shape, and are necessary not because Darcy's law is invalid but because the grids are of finite size. Introduction Darcy's law for horizontal, radial flow may be expressed as: (1) For steady flow, Eq. 1 may be integrated and combined with the real gas law to produce: (2) A similar equation may be derived for stabilized or pseudo-steady flow. It has been observed that at high flow rates, wells do not produce in accordance with Eq. 2, and that a deliverability plot produce in accordance with Eq. 2, and that a deliverability plot (delta p2 vs qsc) on a log-log graph is usually of non-unit slope, suggesting a deviation from Darcy flow. Rawlins and Schellhardt (1936) proposed an empirical equation to account for the apparent deviation from Darcy flow. This equation is the famous backpressure equation, and is given as: (3) where C and n are empirically determined constants. It has been shown [Craft and Hawkins (1959)] that C and n are not constants, and that n varies from unity at low flow rates to 0.5 at high flow rates.
SPE Members Abstract Downward displacement of oil by inert gas injected in a reservoir either at initial oil and connate water conditions or, in a reservoir depleted by waterflooding, results in very high oil recovery efficiencies under strongly water-wet conditions in both unconsolidated and consolidated porous media respectively. Advances made in porous media respectively. Advances made in directional drilling technology and increased understanding of the mechanisms and conditions that maximize recovery efficiencies can make the inert gas injection process of oil recovery feasible for a wide variety of oil reservoirs. This paper presents experimental results and discussion of a presents experimental results and discussion of a series of experiments designed for the study of:production characteristics under immiscible inert gas driven gravity drainage conditions; microscopic mechanisms of displacements and the determination of the rate of production by gravity drainage in capillary tubes having square cross-section; and fluid distributions and oil bank formation using the x-ray computer tomography (CT) scanning facilities we recently established in our laboratory. Introduction Gas injection is being increasingly applied as a secondary or tertiary recovery process, particularly in reservoirs with a reasonable dip particularly in reservoirs with a reasonable dip angle, preferably of high permeability and containin light oil. In such reservoirs a gravity-stable injection scheme is often possible, leading to high sweep efficiencies. There are numerous projects for immiscible gas injection schemes reported in literature which have demonstrated in laboratory experiments and in field performance analysis that very high oil recoveries of residual oil are achieved if gravity drainage (the self propulsion of oil downward in a reservoir) is the dominant production mechanism. An extensive review of the literature is beyond the scope of this paper and can be found elsewhere. Pioneering studies involving the drainage of liquids from unconsolidated sands were done by Stahl et al., and Terwilliger et al. Imagine a vertical column of water-wet glass beads saturated first with brine and subsequently oil flooded to establish initial oil and connate water conditions. Next, consider the injection of air or nitrogen at the top of the column at constant pressure and the production kept at controlled flow rate such that the pore velocity of the gas-oil contact (GOC) is relatively small (e.g. 10(-2) to 10(-1) m/d). Also consider that at the production end at the bottom of the column there is production end at the bottom of the column there is a semipermeable membrane that permits the oil and the water to go through but not the gas when it eventually arrives at the producing end of the column. This experiment has been referred to as "controlled drainage of continuous oil" and has been routinely performed in our laboratory. Overall recovery efficiences were very high (90% to 99% of the oil in place, in glass bead columns of different dimensions). In earlier studies of gravity drainage very low residual oil saturations have also been reported in water-wet media. Dumore and Schols concluded that after the relatively short period in which the main oil production takes place (i.e. in the free fall production takes place (i.e. in the free fall drainage) the drainage of oil in the presence of connate water and injected gas is possibly governed by film flow of bypassed oil. Hagoort stated that gravity drainage can be an effective way of oil production. In his theoretical discussion, the production. In his theoretical discussion, the importance of relative permeabilities to oil was addressed and used th centrifuge technique in order to get the exact representation of field conditions. P. 223
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.41)
- Geology > Geological Subdiscipline (0.34)
SPE Members I. Abstract This paper describes the design, operation and evaluation of a pilot waterflood project initiated in the Lower Ekofisk project initiated in the Lower Ekofisk Formation of the Ekofisk Field located in the Norwegian sector of the North Sea. Previously, a pilot waterflood project in Previously, a pilot waterflood project in the Tor Formation led to approval in 1983 of full scale water injection in the Tor Formation. The Ekofisk and Tor Formations are both low matrix permeability chalks characterized by intense natural fracturing. This natural fracturing has enhanced overall permeability and made commercial production permeability and made commercial production possible from these volumetric solution gas possible from these volumetric solution gas drive reservoirs. The Ekofisk Formation was initially given lower waterflood priority based on spontaneous imbibition laboratory experiments. However, the large values of initial oil in place, in combination with the recognition that mechanisms other than imbibition may play a role in waterflood performance necessitated a pilot be performance necessitated a pilot be performed. Additionally, the pilot was performed. Additionally, the pilot was designed to evaluate rock stability and injectivity in this fractured chalk reservoir. The pilot project consisted of one injector and three producers in an unconfined four spot pattern. As of May 1985, a total of 10 million barrels of water had been injected over a 22 month period. Results have been favorable and have been utilized to justify expansion of the waterflood to the Lower Ekofisk Formation. Factors which were taken into consideration during the analysis include lack of both vertical and horizontal confinement, significant initial gas saturation, influence of gas injection, regional permeability variations, anisotropy and layering effects. Three dimensional simulation results are included which tie all the parameters together and form the basis for parameters together and form the basis for extrapolating results to full field. II. Introduction The Ekofisk Field in the Norwegian Sector of the North Sea is an overpressured naturally fractured chalk reservoir. The 6.7 billion barrels of oil and 10.33 trillion cubic feet of gas, originally in place is split between the Ekofisk (Danian place is split between the Ekofisk (Danian Age) Formation with 2/3 and the Tor (Maastrichtian Age) Formation with 1/3. Production is from three platforms, 2/4 A Production is from three platforms, 2/4 A in the south, 2/4 B in the north and 2/4 C in the center of the field. Recovery by primary depletion is estimated at 24% of primary depletion is estimated at 24% of oil equivalents. The large initial oil in place in combination with low recovery place in combination with low recovery factors necessitated enhanced oil recovery projects be given highest priority. projects be given highest priority. Initial laboratory imbibition experiments indicated a favorable waterflood potential in the Tor Formation, with a poorer recovery potential in the Ekofisk Formation. A Tor Formation pilot waterflood was performed in Ekofisk Field from April 1951 to June 1984 to evaluate in-situ waterflood performance. The results were favorable and used to justify a full field waterflood of that formation. The 30-slot water injection platform 2/4 K was approved to develop an estimated 162 MMBOE reserves utilizing 20 of the available slots to waterflood the northern two thirds of the Tor Formation. P. 153
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.59)
- Europe > United Kingdom > North Sea > Central North Sea > Utsira High > PL 006 > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- (9 more...)
SPE Members Abstract In this study, the production from a well in a solution-gas drive reservoir with interstitial water flow from the transition zone is converted to a slightly compressible liquid for analysis on current decline type curves. Integral transforms for time, pressure, and rate have been created to linearize the diffusivity equation for multiphase flow for certain reservoir conditions. The integral transform variable is called an 'equivalent liquid' variable and it has the same units as the original variable. All the dimensionless definitions using equivalent liquid variables use initial properties. This method concentrates on accounting for the effect of the saturation gradients on the rate-time profile as the bubble point moves out into the reservoir and for the effect of changing fluid properties after late infinite acting flow. The radius of investigation is extended so that it accounts for the change in fluid and rock properties around the wellbore during high rate properties around the wellbore during high rate production periods. This extended definition can production periods. This extended definition can be used to calculate the time when boundary dominated flow is seen at the well. 'Pseudo' relative permeability curves are created for the reservoir drainage volume. We show their shapes will not be similar to the core determined relative permeability curves because the 'pseudo' curves include the effects of saturation and capillary pressure gradients. The effects of gravity segregation, capillary pressure, a skin zone, and some types of formation pressure, a skin zone, and some types of formation permeability hetergeneities are examined for the permeability hetergeneities are examined for the pseudo relative permeability curves and the radius pseudo relative permeability curves and the radius of investigation. Introduction The purpose of this paper is to present a method to analyze multiphase flow from a solutiongas drive reservoir with the Fetkovich type curve or any other decline type curve. With the method presented in this paper, the total mass flow rate presented in this paper, the total mass flow rate from the well is transformed into a volumetric flow rate of a single-phase, slightly compressible liquid. This method can account for the changes in fluid properties with pressure and for the changes in relative permeability with saturation for production from a solution-gas drive reservoir. Some effects of gravity, of capillary pressure, of formation permeability variation, and pressure, of formation permeability variation, and of dispersed flowing water in the transition zone are considered in this study. The effects of nonDarcy flow and layering without crossflow are not considered in this study. Data required for the type curves include mass rate of all the flowing phases, an estimate of the bottomhole flow pressure versus time and a good estimate of the fluid properties. Small bottomhole pressure changes can be treated with rate normalization while large pressure changes should be treated with superposition. Bottomhole pressure estimates are needed to calculate fluid pressure estimates are needed to calculate fluid properties around the wellbore and to help make properties around the wellbore and to help make the history match pseudo relative permeability curve for each phase more uniform from well to well in the field. This paper concentrates on handling saturation and pressure gradients created from constant pressure production below the bubble point during pressure production below the bubble point during late infinite acting, transition, and early boundary dominated flow. The effect of a variable mobility over compressibility ratio in space and time on the radius of investigation is also discussed. For boundary dominated flow, where the oil is the primary flowing phase, our method converges to the Camacho-Raghavan method. Background One of the first mathematical treatments of the flow of fluids in a hydrocarbon reservoir was by Muskat. He derived the diffusivity equation in terms of mass flow as shown in Eq. 1. (1) If single phase flow of a slightly compressible liquid is assumed, then Eq. 1 could be simplified to Eq. 2. P. 69
- Geology > Geological Subdiscipline > Geomechanics (0.49)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- 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)
- (27 more...)
Abstract This report presents the results of a simulation study of the Santa Rosa Colorado EF, RG-14 reservoir located in Eastern Venezuela. The objectives of this study were to determine the quality of the hydrocarbon gas accumulated in the reservoir and to predict oil recoveries under a variety of operating modes. The reservoir contains a condensate gas cap that overlies an oil leg. Depth of the reservoir varies from 6560 ft (1999 m) subsea, at the crest of the dome to 11150 ft (3399 m) subsea on the northern flank. In order to match field performance history, a significant effort was made in developing a geological model based on the depositional environment concept. A fluid characterization model was also constructed for both, reservoir oil and gas condensate using the Peng-Robinson equation of state. A satisfactory history match for 36 years of reservoir performance was achieved using a three dimensional, three phases, multicomponent, compo-sitional simulator. The results at the end of the reservoir history match, indicated that the gas present in the reservoir is mainly methane. A total of five prediction cases were then studied, all intended to provide performance data for technical and economic analysis. The main effects analyzed were: higher gas-oil ratio limit, additional wells, partial and full pressure maintenance and reservoir blowdown. pressure maintenance and reservoir blowdown. The main conclusions drawn from the results of this reservoir simulation study were that drilling and reactivating wells in the oil leg and relocating the injection wells would increase the cumulative production of oil by approximately 9.1 × (10)6 bbl (1.447 × 10(6) m(3). Introduction The Colorado EF (PG-14) reservoir, of the Santa Rosa Field, is located in the northern area of the Anaco thrust fault, in the Eastern Venezuela Basin (Figure 1). This large, rich-gas condensate reservoir with an oil leg, covers 26000 acre (105.2 × 103 m2) and belongs to the fields of the Greater Anaco Area. The RG-14 reservoir was discovered in 1947 and started to produce in April, 1950, when well RG-14 was produce in April, 1950, when well RG-14 was completed as a condensate producer. Dry gas injection was initiated for pressure maintenance in 1955 after reservoir pressure had dropped aproximately 100 psi (690 kpa). Rapid development of the field followed and production was established in the oil leg. Fifty seven wells have been active in the reservoir through December 1985. However, any of these wells had to be shut-in as they were swept by the injected gas or because of water breakthrough. In December, 1985 there were 11 active injection wells and 16 active production wells. The reported cumulative production and injection volumes through December, 1985, were as follows: Cumulative Hydrocarbon Liquid Production (m3): 18.048 × 10(6) Production (m3): 18.048 × 10(6) Cumulative Gas Production (m3): 40.840 × 10(12) Cumulative Water Production (m3): 0.984 × 10(6) Cumulative Gas Injection (m3): 53.520 X 10(12) P. 187
- South America > Venezuela (1.00)
- North America > United States > Colorado (0.81)
- Geology > Sedimentary Geology > Depositional Environment (0.48)
- Geology > Geological Subdiscipline (0.47)
- Geology > Rock Type > Sedimentary Rock (0.46)
- South America > Venezuela > North Atlantic Ocean > Eastern Venezuela Basin (0.99)
- South America > Venezuela > Anzoátegui > Eastern Venezuela Basin > Maturin Basin > Santa Rosa Field (0.99)
- Africa > Angola > South Atlantic Ocean > Kwanza Basin > Block 17 > Rosa Field (0.99)
SPE Members Abstract Oseberg, which is one of the major Norwegian North Sea oil fields, will be produced by injection of associated gas and gas supplied through a pipeline from the Troll field. The two gases have different compositions and neither of them is in thermodynamical equilibrium with the in situ oil. By static multiple contact experiments it has been demonstrated that large component exchanges will occur. Other factors of importance for the reservoir process is a pronounce compositional variation with depth in the oil zone and the existence of a gas cap. A number of relevant measurements and PVT experiments (constant composition expansions and multiple contacts) have been performed in order to obtain data for tuning a qubic Equation of State (EOS) PVT program which is composed of a PVT model and a set of equations. The PVT model consists of a set of well defined pure and pseudo components. Since the PVT program will form the basic for dynamical compositional simulations all the fluids involved must be characterized within a fixed component system. Various approaches have been tried, among then a multivariate lumping scheme. After regression upon 49 experimental data from 4 fluid samples, four PVT models were obtained; two with 6 and two with 22 components. The paper will discuss the choice of experiments and the ideas behind the selection of models, including the choice of pseudo components and regression variables. Introduction During the production of a petroleum reservoir by gas injection the original fluids an injected fluids will interact. Proper modelling o such complex compositional behavior requires a large number of representative PVT data and a well tested PVT model. PVT model. The Oseberg field will be produced by a large scale gas injection scheme. This paper concentrates on the experimental and theoretical PVT study that provides the basic data from which compositional provides the basic data from which compositional effects can be inferred and quantified. Under the present field development plan the following compositional effects have been identified:–In the oil zone there is a pronounced compositional variation by depth, manifested by a negative bubble point pressure gradient. This will lead to compositional variations in the produced fluids. –In the early stage of the field production period there will be only partial pressure maintenance; leading to the release of gas in a part of the oil zone and expansion of the gas cap. When gas saturation does reach its critical value ga wil flow (by gravity segregation) to the top of the oil zone. P. 495
- North America > United States (1.00)
- Europe > Norway > North Sea > Northern North Sea (0.54)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Oseberg Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 079 > Block 30/9 > Oseberg Field > Tarbert Formation (0.99)
- (15 more...)
Abstract This paper gives the geological aspect of a 3-D study on fluvio-deltaic sedimentary bodies and corresponding 3-D conditional simulations obtained by geostatistical methods. It is the continuation of paper SPE 16752 and 16753 (Dallas, 1987). It describes the new sedimentological interpretation of the Scalby formation (U.K.) from the core-drill data, the different correlations performed between the core-drills, the quantification in terms of proportion curves and of variograms of lithofacies sets - and at last some conditional simulations, The image of the cliff is described with the topographical corrections. This new image allows establishing the true correlation with the eleven core-drills located just behind the cliff, and to carry out the accurate structural analysis - in the geostatistical sense of the term - required for the simulations. Henceforth, the core-drill study shows that the evolution of the system and the deposit environment are somewhat different from those deduced from the field data. Therefore, there exists a marine influence in the basal terms, and the unconformity separating the major units is significant and probably regional. However, the field data remain essential for the geostatistical study. The upper unit is composed of multistoried and highly sinuous channels deposited in a typical fluviodeltaic environment. The lower unit is principally fluvial-dominated but it has been influenced by the tides, The well-to-well correlations show that the overall geometry is of a sand-sheet type. The interval are more or less of the same thickness ; this fact, together with the low rate of sedimentation and the low thickness/lateral extension ratio of the terms suggest low subsidence and high lateral divagations of the distributaries. Correlations in terms of lithostratigraphy, lithology, porosity and permeability have been made between the porosity and permeability have been made between the core-drills in the grid where the distance was progressively reduced. The illustrations from the correlation progressively reduced. The illustrations from the correlation given in this paper emphasize the lateral variations in several parameters (facies, petrophysical…) between wells in the same lithostratigraphic unit over short distances. Interpreted geological data have been digitised and then quantified. This quantification is represented by vertical proportion curves and by variograms which are the input parameters for the calculation of the simulations. 2 and 3-D conditional simulations of the studied reservoirs are carried out and then analysed. These random set conditional simulations are obtained by an original method elaborated by our IFP-CG group. In this paper, we show the influence of the input parameters on the results. These parameters have been parameters on the results. These parameters have been relatively easily fitted due to a large amount of information. The obtained simulations then display an aspect very similar to that of the digitised cliff. The horizontal ranges have an influence over the continuity restoration. Thus a large range gives a strong continuity of the simulated image, while a short range reduces the size of the simulated sedimentary bodies. The ranges are calculated and then fitted using available data. When these data are insufficient, other "a priori" information is introduced. priori" information is introduced. The vertical proportion curves of the different facies plays an important part in the lithofacies plays an important part in the lithofacies distribution. These curves are easily calculated from the coredrills. P. 463
- Geology > Geological Subdiscipline > Stratigraphy > Lithostratigraphy (0.90)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Deltaic Environment (0.61)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.55)
SPE Members This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Write Publications Manager, SPE, P.O. Box 833836, Richardson, TX 75083-3836. Publications Manager, SPE, P.O. Box 833836, Richardson, TX 75083-3836. Telex, 730989 SPEDAL. Abstract High velocity fluid flow down hydraulic fractures will create pressure gradients that are proportional to the square of the velocity. As proportional to the square of the velocity. As such, Forchheimer's equation, rather than Darcy's law must be used to correctly estimate the pressure gradients near the wellbore and, consequently, the flow behavior of the hydraulically fractured well. To properly use the Forchheimer equation, one must know the value of beta, which is the inertial flow coefficient. Cooke measured values of beta for various sizes of Brady sand at several different closure pressures. Cooke's correlation has been widely used in the industry but we have found that the correlation did not span the permeability range needed for all situations. Specifically, data are needed to estimate the pressure gradients of gas flowing through high strength, high permeability, man-made proppants. We also need the inertial flow data for proppants. We also need the inertial flow data for sand that has been severely crushed. A laboratory system has been constructed to investigate hig velocit flow through fracture proppants. From test data, both proppant proppants. From test data, both proppant permeability and the inertial flow coefficient can permeability and the inertial flow coefficient can be computed. The proppants tested included 12–20 and 20–40 mesh samples of Brady sand, Interprop Plus, and Carbolite. An improved correlation of Plus, and Carbolite. An improved correlation of inertial flow coefficient as a function of proppant permeability and initial mesh size has been permeability and initial mesh size has been developed using our laboratory system. The results indicate that the inertial flow coefficient depends upon the initial mesh size of the proppant, and is independent of the proppant type. Grain size distribution was found to be a factor controlling the inertial flow coefficient for a given fracture proppant. It was found that different samples with similar permeabilities and inertial flow coefficients also had similar grain size distributions. A variation in the pore pressure of the nitrogen used in the experiments was shown to have a significant effect on the inertial flow coefficient. The permeabilities calculated from the Forchheimer equation exhibited the same trend of decreasing permeability with increasing pore pressure as the Klinkenberg relationship for Darcy pressure as the Klinkenberg relationship for Darcy flow. Slip flow was found to influence the results significantly at Reynolds Numbers below 0.1. Introduction To increase production from a low permeability gas reservoir, mos wells have to be fracture treated. When the fracture is created, a granular propping agent is pumped into the fracture to keep propping agent is pumped into the fracture to keep the fracture from closing. The conductivity of the fracture is usually very large when compared to the formation. Because the fracture width is small and the fracture permeability is large, the velocity of gas flowing down the fracture is very high. In most cases, the velocity of the gas in the fracture is so large that it cannot be adequately modeled using Darcy's Law. Darcy's Law assumes that fluids are flowing throug porous medi under laminar conditions. In a fracture, the flow is not laminar. The high velocity flow will be controlled by turbulent or inertial effects. The turbulent flow of gases through porous media has been discussed by several authors. Hubbert theorized that the deviation of fluid flow from Darcy's law that was attributed to turbulent flow was actually caused by inertial forces. P. 559
Abstract Eighteen years ago Exxon initiated the development of a three-dimensional geological modeling program to automate the generation Of geologic maps and cross sections from exploration data. This program is also well suited for providing a highly complex reservoir description for reservoir simulation and has become a standard operating procedure for many of Exxon's simulation projects. Because these models are directly interfaced to the reservoir simulator, the reservoir engineer can easily utilize the complex reservoir description provided by the geologist for field development planning. In addition, the reservoir engineer can routinely and readily update his model with new data or interpretations and quickly provide consistent maps and sections for provide consistent maps and sections for assessing results of development drilling. Introduction The importance of geology to prediction of reservoir performance is recognized by reservoir engineers and most reservoir studies take the geology of the porous fluid system into account some way. However, translating an intricate geological picture into a useful form for computer simulations can be time-consuming and often frustrating for the geologist-engineer team. Especially difficult are qualitative inferences the geologist must make: How does he get his ideas of the extent and continuity of shale lenses and degree of inter-communication of individual sands into the reservoir model? A three-dimensional modeling program that Exxon originally developed for exploration work has provided an answer. With such a program, the geologist can input structural and stratigraphic concepts as a series of computer "grids" honoring the geologic "tops". Interpolations of logged porosity and other data from wells are controlled by this stratigraphic "framework" and fill a 3-D matrix of "cells". Additional geological features critical to reservoir performance can be added to complete the geologist's picture of the reservoir. picture of the reservoir. In this paper, we will explain how our computer models of reservoir geology are built; the geological concepts which are considered; and how we use the models in reservoir simulation. BUILDING A BASIC 3-D GEOLOGIC MODEL The 3-D matrix of cells The Exxon program models geologic space as a matrix of many hundreds of thousands of points which can be considered as tabular points which can be considered as tabular cells. Their areal dimensions are usually 50 to several hundred feet, but may range to more than a kilometer in larger fields. In vertical dimension, 1-foot cells are most common in U.S applications with 3-decimeter and 1-meter cells used overseas. These cells are usually much smaller than the reservoir blocks specified in reservoir simulators. Figure 1 shows a geologic 3-D model. The wells and seismic data provide detailed structure, but this model is datummed on the uppermost surface to reduce the number of cells to be computed. P. 585
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.36)