Directional Permeability Research Articles

Hydrogeological testing to characterize a fractured granite

A comprehensive program of in situ testing has been carried out in an iron ore mine in Stripa, Sweden, to investigate the problems of obtaining a hydrogeological characterization of a fractured granite rock mass. The field investigations consisted of: (1) the collection of fracture geometry and borehole injection test data to determine directional permeabilities, (2) a macropermeability experiment to determine the bulk rock mass permeability, (3) groundwater sampling for investigations of geochemistry and isotope hydrology, (4) pump testing of surface wells, and (5) tracer tests to determine effective porosity. This report summarizes results from all but the last item, the tracer work, which had not been carried out when the field work ended in 1981.

Fireflooding a High-Gravity Crude in a Watered-Out West Texas Sandstone

Summary This paper describes the results, operational problems encountered, and the ongoing technical evaluation of an in-situ combustion pilot project in the North Ward-Estes field in Ward County, TX (Fig. 1). This sandstone reservoir was discovered in 1929 and has been under waterflood since 1955. Even though the reservoir characteristics were marginal in comparison with the screening criteria for in-situ combustion, laboratory tests indicated that this process could be viable. Introduction The North Ward-Estes field is an anticlinal structure of lagoonal deposition 18 miles (28.9 km) long and 4 miles (6.4 km) wide, trending north to south along the western edge of the central basin platform. The Yates formation is located at a depth of 2,400 to 2,800 ft (732 to 853 m). This Permian age reservoir consists of seven sand members trapped by dense dolomites and is limited a really by shales and evaporites. Approximately 10% of the rock volume consists of clay: montmorillonite, 80 to 85%; illite, 5 to 10%; chlorite, 1 to 5%. Some minor evidence of fracturing has been indicated, and a northwest-southeast directional permeability is also present. The G.W. O'Brien Well 4 was drilled in April 1929 by Gulf Oil Exploration and Production Co. After this discovery well, approximately 2,000 wells producing from the Yates and Queen formations were drilled over an area of about 30,000 acres (121 × 10(6) m2). By 1955 most of the primary oil was depleted by solution gas drive. At that time, a waterflood was initiated that still remains in operation. Production and injection have been from open hole multi sand completions, which do not lend themselves to reliable calculations of oil saturation. Approximately 350 million bbl (55 × 10(6) m3) of oil have been produced from this reservoir since discovery. A dry forward in-situ combustion pilot was initiated on April 11, 1978. This project, known as the Section 10 combustion project, was implemented in the J-2 sand, which is the lowest of seven Yates sand members (Fig. 2). The rock and fluid properties are given in Table 1. Comparison of project parameters with various screening criteria indicated that the reservoir oil saturation was marginal (Table 2). All other parameters were within the minimum criteria. Laboratory experiments using produced fluids and preserved core demonstrated the applicability of an in-situ combustion process in this watered-out reservoir. We initiated a pilot project to substantiate these tests and to answer four major objectives:Can ignition be obtained and can combustion be propagated in a light-gravity crude?Can flue gas be isolated from other producing sands?Can produced flue gas be disposed of readily?Will the oil-production rate be increased? This pilot was implemented in two phases. We conducted Phase 1 in an inverted 10-acre (40 469-m2) five- spot pattern. High O2 and low CO2 concentrations in gas samples from offset producing wells indicated marginal bum quality. Rapid flue gas migration and the evidence of a low-quality bum caused this phase to be terminated in April 1979. In Nov. 1978, we began Phase 2 in an inverted 40-acre (161 875-m2) nine-spot pattern west of the Phase 1 pilot in a location having a thicker sand section. The initial O2 and CO2 concentrations in the produced flue gas indicated a better burn quality in this area. An observation well was dulled and cored behind the calculated location of the combustion zone to determine whether ignition was obtained and whether combustion propagation was possible in this formation. Another observation well was drilled and cored in an attempt to locate the leading edge of the combustion zone and to determine whether an oil bank was developing. JPT P. 2244^

Recent Field Results With New Bits

Summary Multiple pulse tests were conducted in Saudi Arabia to yield information about permeability anisotropies in the Ghawar oil field. Because of wide well spacing and high permeability, sensitive quartz pressure gauges were used to record pressure changes. Pressure data from observation wells were processed to filter out noise and to provide easily definable pulse responses. Calculated pulse test results then were analyzed for indications of directional permeability. Introduction To date, three Multiple production pulse tests have been conducted in the Ghawar oil fileld in Saudi Arabia in a continuing effort to improve the reservoir description used in reservoir simulation models of the area. Results from and procedures used in a 1977 test are presented by McIntosh et al.1 The results of the other two tests, which were conducted in 1979, are the subject of this paper. The performance and accuracy of any reservoir simulation study are related intimately to the completeness of the reservoir description of the field being modeled. Pulse tests, interference tests, and single-well pressure transient tests all provide valuable information without reservoir properties. The three pulse tests conducted in Ghawar were run to investigate the area distribution of permeability and, in particular, to test for the presence of area permeability anisotropies in the productive formation. Major directional permeability can have a dramatic effect on fluid movement in the reservoir; therefore, the description of permeability trends is a key element in reservoir modeling. Results from the pulse tests are being integrated with results from cores, logs, and other well tests to improve overall description of the reservoir. The previous pulse test conducted in 1977 proved the feasibility of pulse testing in the high-permeability, wide well-spacing environment of Ghawar. The two tests discussed in this paper were located to provide good areaI coverage over the central portion of Ghawar. One test was run near an area that previously had been identified by buildup testing as having ultrahigh permeability. Of the three well pairs involved in this test, one of them indicated very high interwell transmissibility. We believe that this high permeability is associated with a localized thin facies near the top of the reservoir, which has not been described geologically to date. For the six well pairs comprising the two tests discussed here, interwell distances varied from a minimum 2,921 ft (890 m) to a maximum 4,499 ft (1371 m). The observed time lags and pressure responses varied from 72 to 1,728 minutes and from 0.12 to 7.05 psi (0.83 to 48.6 kPa), respectively. First pulse responses and first inverse pulse responses were recorded in three well pairs. For the other three well pairs, second pulse responses were recorded also. Reservoir Description The reservoir tested and described in this paper is in the Arab-D formation, the major productive formation in the Ghawar field. This formation is a massive carbonate structure grossly subdivided into five separate zones. The reservoir of interest comprises interbedded layers of limestone and dolomite, and it is quite heterogeneous both vertically and areally. In general, there is a degradation in both porosity and permeability vertically with increasing depth in the reservoir. Some vugular porosity occurs throughout the reservoir, in both limestone and dolomite facies.

In‐Situ Determination of Three‐Dimensional Aquifer Permeabilities

ABSTRACTIn conventional methods of aquifer tests, homogeneous and isotropic formations are assumed. In many instances, however, aquifers are anisotropic. To resolve this problem, three‐dimensional flow equations in homogeneous, anisotropic and leaky aquifers are derived. With the equation and method outlined in the report, we can determine the three components of directional permeability (x, y, and z) in the presence of leakage, and determine the statistical distribution of fractures and stream channels. Field tests that verify our theory are presented.

A New Method To Measure Directional Permeability

Introduction and Theory The problem of measuring directional permeability by applying Darcy's law has been known for a long time, but so far it has been left unresolved. Here we show that for two-dimensional cases of anisotropy, three measurements must be made on a laboratory sample to calculate the maximum and minimum permeability from the data. These are (1) Angle B, which shows the direction of flow with respect to the direction of maximum permeability, (2) Angle A, which shows the direction of permeability, (2) Angle A, which shows the direction of flow with respect to the direction of the driving force gradient, and (3) the R11 element of the resistivity tensor that appears when Darcy's law is given the special form Rij qu=-grad p................... (1) Here Rij is the second-rank (symmetric) resistivity tensor defined by the transformation rule (2) In Eq. 2, lambda ii and lambda jj are the direction cosines between an i, j-axis frame and any other i, j- (rotated-) axis frame. Specifically, it is clear that an angle, - B, always can be found such that Rij will take on a diagonalized form. It and easy to prove that the inverses of R1 and R2, respectively, give the maximum and minimum Darcian permeabilities since the i, j-axis frame coincides with the permeabilities since the i, j-axis frame coincides with the principal directions of the permeability tensor. principal directions of the permeability tensor. JPT P. 1142

Directional permeability of asymmetrically oxidized poly(L‐methionine) film to oxygen dissolved in water

AbstractThe permeability of an asymmetrically oxidized poly(L‐methionine) film to oxygen dissolved in water was examined. It was recognized that the permeability along an increasing gradient of oxidized methionine composition is higher than the gradient is reversed. A qualitative analysis of this result was presented in terms of the oxygen solubilities into the film and water absorbed in the film.

Drainage systems developed by sapping on Earth and Mars

Research Article| March 01, 1982 Drainage systems developed by sapping on Earth and Mars Charles G. Higgins Charles G. Higgins 1Department of Geology, University of California, Davis, California 95616 Search for other works by this author on: GSW Google Scholar Author and Article Information Charles G. Higgins 1Department of Geology, University of California, Davis, California 95616 Publisher: Geological Society of America First Online: 01 Jun 2017 Online ISSN: 1943-2682 Print ISSN: 0091-7613 Geological Society of America Geology (1982) 10 (3): 147–152. https://doi.org/10.1130/0091-7613(1982)10<147:DSDBSO>2.0.CO;2 Article history First Online: 01 Jun 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation Charles G. Higgins; Drainage systems developed by sapping on Earth and Mars. Geology 1982;; 10 (3): 147–152. doi: https://doi.org/10.1130/0091-7613(1982)10<147:DSDBSO>2.0.CO;2 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyGeology Search Advanced Search Abstract During falling tides the foreshores of many beaches develop steep-headed incised drainageways that resemble and may be analogous to some larger scale drainage systems of both Earth and Mars. The beach systems are formed entirely by groundwater outflow and sapping where the water table intersects the beach face. At this intersection outflow dilates the sand and moves surface grains outward into the runoff. This forms gully heads, which then advance headward up the slope in directions largely controlled by directional permeability. Activity ceases when the water table falls below the level of the gully heads.Rather extensive, though miniature, angulate-dendritic drainage systems can result from this process, but sapping has rarely been recognized as a major factor in the formation of larger scale drainage systems on Earth. On Mars, however, the analogy of the beach models may help explain the origin of some large valleys as a result of sapping by outflow of groundwater derived from thawed ground ice. Such relict effects of sapping may be recognizable on Mars because they have not been obscured by surface processes, as they tend to be on Earth. Re-evaluation of many terrestrial fluvial systems may reveal that sapping has been a common and important valley-forming process here too. This content is PDF only. Please click on the PDF icon to access. First Page Preview Close Modal You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

Norman Wells - A New Look at One of Canada's Largest Oil Fields

Summary A major development plan for the Norman Wells oil field in the Northwest Territories has been based on a recent synergistic geological and engineering study of the reservoir. Information from oriented cores, well tests, fluid and pressure surveys, outcrop studies, and surface photos have shown that natural vertical fractures present in the reservoir have a strong N30 deg. E orientation. The proposed development plan will make use of the directional permeabilities resulting from natural fractures. Introduction Oil sands and hydrocarbon seepages along the MacKenzie River in the Northwest Territories have been reported since the late 1700's by explorers and fur traders. In 1920, Imperial Oil Ltd. drilled the discovery well near oil seepages at Norman Wells 900 miles (1500 km) north of Edmonton, Alta. (Fig. 1). The remote location of the field delayed development until the early 1940's when, under the Canol Agreement, the U.S. Army, Canada, and Imperial Oil drilled 60 wells, expanded the existing refinery, and constructed a road and pipeline to Whitehorse 620 miles (1000 km) to the southwest. Pool production peaked at 4,400 B/D (700 m3/d) in 1944. The pipeline to Whitehorse was dismantled after 1945, but the pool has continued to supply northern Canada. Demand has grown to the present level of 3,000 B/D (480 m3/d).Total pool production to the end of 1980 under primary solution-gas drive has been less than 4% of the estimated 630 million bbl (100 x 106 m3) of original oil in place (OOIP). The MacKenzie River overlies the bulk of the reservoir, and since the reef is relatively shallow at a depth of 1,000 to 1,600 ft (300 to 500 m), development has been limited to three producing areas known as the Mainland, Goose Island, and Bear Island (Fig. 2). Typical-well oil rates have declined by 50% to a range of 60 to 500 B/D (10 to 80 m3/d). The present GOR's have escalated to between 2,000 to 4,000 cu ft/bbl (350 to 700 m3/m3) from a solution GOR of 335 cu ft/bbl (60 m3/m3).Activity has increased significantly since 1979 with the drilling of seven delineation wells from grounded river-ice platforms and land areas, seven highly deviated wells for water injection and production, and one horizontal well intersecting 4,000 ft (1200 m) of reservoir rock from the Mainland to the central pool area under the river.A line-drive waterflood employing 13 wells was started in 1980 for the Mainland area, and an extensive monitoring system has been installed to measure fluid production and injection, GOR'S, and pressures by individual well and zone. In March 1980, an application was made to the Canadian Federal Dept. of Indian Affairs and Northern Development for approval to expand the Mainland waterflood to a fieldwide pattern waterflood system. Reservoir Geology Summary Hydrocarbons at Norman Wells are pooled in the Devonian Kee Scarp formation limestone reef buildup, which is 15 miles (25 km) long and 5 miles (8 km) wide. The reef complex began to develop during Upper Middle Devonian time on shale banks of the Hare Indian formation (Fig. 3). Minor variations in sea level localized major reef growth on a thin open marine platform along the basinward edges of the Hare Indian shales. Reef growth proceeded during two major upward shoaling cycles and was terminated by the advancing clastic sediments of the Canol and Imperial formations, which serve as the top seal for the reef buildups. The Kee Scarp reef at Norman Wells attains a maximum thickness of 525 ft (160 m) with a reservoir thickness of 360 ft (110 m). The regional structural dip is about 4.5 deg. to the southwest. Oil is trapped stratigraphically in the extreme updip end of the reef buildup. There is no gas cap, and a limited water leg provides no pressure support. JPT P. 985^

Rock mass characterization for storage of nuclear waste in granite : Witherspoon, P A; Gale, J; Nelson, P Proc 4th Congress International Society for Rock Mechanics, Montreux, 2–8 Sept 1979, Vol 2, P711–718. Publ Rotterdam, A A Balkema, 1979

The rock mass characterization in granite adjacent to an iron mine at Stripa, Sweden is being carried out by four different methods. The mechanical characterization includes monitoring the responses to thermal loading of jointed rock in situ, and mechanical tests on cores from 25 mm to 1 m in diameter. Geological characterization includes detailed surface mapping, subsurface mapping, and core mapping. Geophysical characterization uses a variety of borehole techniques, with emphasis on sonic methods. The hydrologic characterization is done through injection tests, pump tests, water pressure measurements, and controlled inflow tests to tunnels. Since the data are not yet complete, only tentative conclusions can be drawn regarding the best combinations of techniques for rock-mass characterization. Mapping studies are useful in defining continuity and fracture-system geometry. They do not give aperture, a factor significant in terms of both water flow and the displacements due to heating. Of the geophysical techniques, sonic methods appear most effective in fracture definition; other methods, gamma and neutron particularly, give data on radionuclide and water content and need further analysis with geologic and hydrologic data to determine their significance. Hydrologic work yields primarily aperture data, which with fracture geometry can be used to calculate directional permeabilities. Pressure measurements may provide one means of assessing fracture continuity. Finally, laboratory tests on large cores suggest considerable refinement in testing techniques may be needed before stress-aperture data can be extrapolated from laboratory to field. (LK)

Rock Mass Characterization for Storage of Nuclear Waste in Granite

The rock mass characterization in granite adjacent to an iron mine at Stripa, Sweden is being carried out by four different methods. The mechanical characterization includes monitoring the responses to thermal loading of jointed rock in situ, and mechanical tests on cores from 25 mm to 1 m in diameter. Geological characterization includes detailed surface mapping, subsurface mapping, and core mapping. Geophysical characterization uses a variety of borehole techniques, with emphasis on sonic methods. The hydrologic characterization is done through injection tests, pump tests, water pressure measurements, and controlled inflow tests to tunnels. Since the data are not yet complete, only tentative conclusions can be drawn regarding the best combinations of techniques for rock-mass characterization. Mapping studies are useful in defining continuity and fracture-system geometry. They do not give aperture, a factor significant in terms of both water flow and the displacements due to heating. Of the geophysical techniques, sonic methods appear most effective in fracture definition; other methods, gamma and neutron particularly, give data on radionuclide and water content and need further analysis with geologic and hydrologic data to determine their significance. Hydrologic work yields primarily aperture data, which with fracture geometry can be used to calculate directional permeabilities. Pressure measurements may provide one means of assessing fracture continuity. Finally, laboratory tests on large cores suggest considerable refinement in testing techniques may be needed before stress-aperture data can be extrapolated from laboratory to field. (LK)

Transient Flow in Elliptical Systems

Abstract This study presents analytical solutions to elliptical flow problems that are applicable to infinite-conductivity vertically fractured wells, elliptically shaped reservoirs, and anisotropic reservoirs producing at a constant rate or pressure. Type curves and tables are presented for the dimensionless flow rate and the dimensionless wellbore pressure for various inner boundary conditions ranging from K = 1 1, which corresponds to a circle, to K =, which corresponds to a vertical fracture. For elliptical reservoirs, K is the ratio of the major to minor axes of the inner boundary ellipse; for anisotropic reservoirs, it is the square root of the ratio of maximum to minimum permeabilities. Introduction Flow in a homogeneous and isotropic porous medium usually will be radial or linear, depending on the shape of the boundary. But in the area surrounding a vertical fracture, an anisotropic formation, or an aquifer with an elliptical inner boundary, flow will be elliptical.The study of elliptical flow in porous media is more recent than the usual radial and linear flow studies, but even elliptical flow studies date back at least several decades. The earliest discussion of steady-state elliptical flow usually is attributed to Muskat. He presented a steady-state analytical solution for the now from a finite-length line source into an infinitely large reservoir.One of the classic papers on elliptic flow by Prats et al. considered flow of compressible fluids from a vertically fractured well in a closed elliptical reservoir producing at a constant pressure. Prats et al. also producing at a constant pressure. Prats et al. also presented a solution for long times for the presented a solution for long times for the constant-rate case.Gringarten et al. found that older studies by Russell and Truitt (where flow is to a vertically fractured well) are unsuitable for short-time analysis. Gringarten et al. presented analytical solutions for fractures with infinite conductivity and with uniform flux. These solutions were for both closed squares and infinite reservoirs produced at a constant rate.In the last few years considerable work has been done on fracture systems, including numerical solutions and a semianalytical solutions for both finite and infinite fracture conductivities. Most of these studies, however, have not used the concept that the fracture is an elliptical flow system. Nevertheless, the results they obtain are important for well testing.Another problem related to elliptical flow is flow through an anisotropic porous medium. For this problem, a line source solution and a long-time problem, a line source solution and a long-time approximation presented by Earlougher are available for the constant-rate case.The purpose of this paper is to study elliptical flow in a broad sense with regard to reservoir engineering problems and to see whether these problems can be problems and to see whether these problems can be solved and whether elliptical problems can be handled in a unified, consistent manner. Development of Elliptical Flow Models The flow from an isotropic and homogeneous medium to a map usually will be radial, but lack of homogeneity will distort the radial flow geometry. In particular, flow will be elliptical through a porous particular, flow will be elliptical through a porous medium with directional permeability distribution (simple anisotropy). The inner geometry of a well also can distort radial flow geometry. For example, the flow will be elliptical if the well has an infinite-conductivity vertical fracture. Elliptical flow also will be encountered in flow from an aquifer to a reservoir that has an elliptical boundary at the oil/water contact. SPEJ P. 401

History Matching in Two-Phase Petroleum Reservoirs: Incompressible Flow

Abstract The estimation of porosity, absolute permeability, and relative permeability-saturation relations in a two-phase petroleum reservoir is considered The data available for estimation are assumed to be the oil flow rates and the pressures at the wells. A situation in which the reservoir may be represented by incompressible flow of oil and water also is considered. A hypothetical, circular reservoir with a centrally located producing well is studied in detail. In principle, the porosity can be estimated on the basis of saturation behavior, absolute permeability on The basis of pressure behavior, and permeability on The basis of pressure behavior, and coefficients in the relative permeability-saturation relations on the basis of both saturation and pressure behavior. The ability to achieve good pressure behavior. The ability to achieve good estimates was found to depend on the nature of the flow in a given situation. Introduction The estimation of petroleum reservoir properties on the basis of data obtained during production, so-called history matching, has received considerable attention. By and large, the development of theories for history matching and their application have been confined to reservoirs that can be modeled as containing a single phase. (Wasserman et al. considered the estimation of absolute permeability and porosity in a three-phase reservoir permeability and porosity in a three-phase reservoir by the use of pseudo single-phase model.) Since in the single-phase case only a single partial-differential equation is needed to describe partial-differential equation is needed to describe the reservoir, identification techniques can be tested most conveniently on such a system. The customary parameters to be estimated are the rock porosity (or the storage coefficient) and the porosity (or the storage coefficient) and the directional permeabilities (or the transmissibilities), which are not uniform throughout the reservoir but a function of location. The history matching of single-phase reservoirs through the estimation of these functional properties now appears to be understood quite well. Numerical algorithms have been thoroughly studied and tested. The most difficult aspect is the ill-conditioned nature of the problem arising from the large number of unknowns problem arising from the large number of unknowns relative to the available data. A recent study has elucidated the basic structure of single-phase history-matching problems and has shown how the degree of ill-conditioning may be assessed quantitatively. Reservoirs generally contain more than one fluid phase, however, and consequently are described by phase, however, and consequently are described by mathematical models accounting for the multiphase nature of the system. The porosity and absolute permeabilities still must be estimated as in the permeabilities still must be estimated as in the single-phase case. In addition, it may be necessary to estimate the relative permeability-saturation relationships. Ordinarily, relative permeability vs saturation curves are determined through experiments on core samples. Because it may be difficult to reproduce actual reservoir flow conditions in a laboratory core sample, it is desirable to consider the direct estimation of relative permeability-saturation relationships on the basis of permeability-saturation relationships on the basis of reservoir data that ordinarily would be available during the course of production. This paper represents an initial investigation of the complex identification problem in two-phase reservoirs. The major objective problem in two-phase reservoirs. The major objective of this study is to investigate the feasibility of parameter estimation in two-phase reservoirs in parameter estimation in two-phase reservoirs in which the reservoir is described by a two-phase incompressible flow model. In the next section we present basic equations governing two-phase (oil-water) reservoirs. We first define the general history-matching problem for these reservoirs and then consider a hypothetical reservoir, circularly symmetric with a central producing well in which the flow may be taken as producing well in which the flow may be taken as incompressible. The radial flow reservoir represents a situation in which oil is produced from a water drive. We wanted to estimate reservoir properties based on data obtained at the well. Considering the flow as incompressible enables us to draw a direct comparison to the classic incompressible linear-flow case for which the problem of estimating relative permeabilities is well established. Thus, we permeabilities is well established. Thus, we seek to understand fully the incompressible flow case as a prelude to the general problem of history matching in two-phase compressible flow reservoirs. SPEJ P. 398

Noradrenaline induced secretion of nonelectrolytes through frog skin.

Addition of noradrenaline (4 x 10(-5) M) to the inner bathing fluid in the skin of the frog Rana esculenta results in increased unidirectional fluxes of urea, thiourea, N-methyl-thiourea, N-N'-dimethylthiourea and mannitol. Fluxes towards the external medium (phi o) undergo a much greater increase than those moving the opposite direction (phi i). The effect of noradrenaline on phi o is higher for urea and thiourea than mannitol, while its effect on phi o thiourea derivatives is related to lipid solubility. This phenomenon does not occur for phi i of the same molecules. FCCP (10(-6) M) pretreatment strongly inhibits the noradrenaline effect on phi o. In skin pretreated with colchicine (2 x 10(-5) M) both urea fluxes are increased to the same extent by noradrenaline. Noradrenaline is concluded to exert two separate effects: (1) a change in permeability in both directions; (2) a secretion of nonelectrolytes towards the external fluid. Such secretion is most probably associated with the hormone-induced secretion of fluid and electrolytes, perhaps mediated by an exocytotic mechanism.

Alkaline Waterflooding: Design and Implementation of a Field Pilot

Raimondi, P., SPE-AIME, Gulf Research and Development Co. Gallagher, B.J., SPE-AIME, Gulf Energy and Minerals Co.-U.S. Ehrlich, R., SPE-AIME, Gulf Research and Development Co. Messmer, J.H., SPE-AIME, Gulf Research and Development Co. Bennett, G.S., SPE-AIME, Gulf Research and Development Co. A field trial of caustic waterflooding in a Queen sand lens in the North Ward-Estes field is described. Comparison of results with projections for a conventional waterflood, while uncertain, indicate that about 25 percent more oil was produced. Operational problems are discussed. Introduction The North Ward-Estes field, Ward and Winkler Counties, Tex., has been under successful water drive for many years. However, a considerable amount of oil is left behind even in the water-swept zones. Laboratory tests have indicated that the oil displacement efficiency could be improved significantly by adding a high-concentration slug of sodium hydroxide (NaOH or caustic) to the flood water. In the swept zone, the laboratory-measured improvement was about 125 bbl/acre-ft. This is attributed to generation of surfactants by the reaction of caustic with organic acids in the oil and the effect of these surfactants on multiphase flow, primarily a wettability shift in the water-wet direction. These mechanisms have been discussed in other papers. The field test is being conducted in the Queen sand, East Flat area of the North Ward-Estes field. This area was discovered in 1969 and development drilling was completed during 1970 with the drilling of 20 additional wells. The oil production rate peaked at 85,000 bbl/ month during mid-1970, followed by a rapid decline in rate resulting from the highly undersaturated nature of the oil. To offset this decline, full-scale water injection was begun in late 1970. Production response to water injection was almost immediate and a peak rate of 40,000 bbl/month was reached in early 1971. To test the laboratory results, a 5-acre inverted fivespot pattern was developed by drilling four water-injection wells, WI-79 through WI-82. around an existing producing well, Well 874 (Figs. 1 and 2) in an area of the field that was presumed to have not yet been affected by the ongoing waterflood. The objective was to determine the effect of a caustic slug injected early in the life of a waterflood. This paper describes the test area, the laboratory evaluation, the design and conduct of the test, the production behavior and an analysis of the recovery. The production behavior and an analysis of the recovery. The test was still in progress when this paper was written. Reservoir Description Geologically, the Queen sand is a channel-type deposit. These deposits exhibit strongly directional permeabilities, generally northwest-southeast. Normal to permeabilities, generally northwest-southeast. Normal to this, the permeability is reduced to one-fourth or less of the dominant permeability. The East Flat Queen sand is rather fine-grained argillaceous, becoming increasingly anhydritic and dolomitic away from the central portion until reservoir development ceases to occur. Permeability and porosity pinchouts control the reservoir limits. However, northwest of Well 838 (Fig. 1) and along the southwest boundary, little geologic control is available and some water influx may have occurred. Fig. 3 shows a typical log section. The presence of gypsum and dolomite above and below the sand is evident from visual and other observations. X-ray diffraction analysis of producing sands gave 80 percent quartz and 10 percent feldspar as well as varying amounts of illite and montmorillonite clays. JPT P. 1359

Interference Analysis for Anisotropic Formations - A Case History (includes associated paper 6406 )

Many formations, such as channel sand, appear to exhibit simple ky-kxanisotropy. Directional permeability has an important effect onplanning fluid-injection oil recovery. The method discussed in thispaper uses data obtained during water injection to determine major andminor permeability axes and the orientation of the unknown permeability matrix. Introduction It has long been known that many formations appear toexhibit simple ky-kx anisotropy. This model also may beapplicable for formations containing trending fracturepatterns. Knowledge of directional permeabilityobviously would have an important effect on planningreservoir development, particularly for fluid injectionoperations. A recent study by Papadopulos outlines methods for interference analysis in anisotropic formations. Themethod is used here to analyze a field water-injection testto determine major and minor permeabilities and theorientation of the unknown permeability matrix. The method also may be extended to pressure falloff (orbuildup) interference analysis. The theory of flow of either fluid or heat through ananisotropic medium is well established. A brief reviewof this information is sufficient here. We consider that awell is produced at a constant volumetric rate in aninfinite, anisotropic medium. The formation has aconstant thickness and porosity, and the total systemeffective compressibility is constant. Collins has presentedperhaps the best-known solution to this problem in thearea of oil production technology. In the mid-1960's, aseries of papers appeared in the groundwater hydrologyliterature dealing with the problem of well testanalysis for anisotropic aquifers. Studies by Hantush, Papadopulos, and Walton are particularly notable. ThePapadopulos study appears to be well-suited for applicationto analysis of oil and gas well test data and serves asthe basis for this study. The purpose of this paper is topresent analysis of actual field data with the Papadopulosmethod in a form readily useable by petroleum engineers.The method is extended to falloff data. Theory The Collins solution for the pressure field caused by awell producing from an anisotropic reservoir is correct, but it assumes the directions of the major and minorpermeability axes are known and are aligned with thewell-location coordinate system. In the general well testanalysis situation, the direction of the major permeabilityaxis would be unknown. Fig. 1 shows the known welllocation x-y coordinate system with the unknown permeability axes, X-Y, oriented at some unknown angle 0.The pressure at (x, y, t) caused by a line-source well at theorigin was presented by Papadopulos: 2 h (pi - px, y, t)kxxkyy - kxy ----------------- =141.2 q B 1- Ei .....(1)2 kxx = 1/2{(kxx+kyy) + [(kxx-kyy)2+4kxy2] 1/2}....(2) kyy = 1/2{(kxx+kyy) − [(kxx-Kyy)2+4kxy2]1/2}.....(3) kxx − kxx= arctan ......................(4)kxy JPT P. 1290^

Delineating a Subsurface Fracture System in A Petroleum Reservoir-An Experiment

The use of a multisensor array has shown that hydraulic pressurization can be useful in delineating subsurface fracture systems in petroleum reservoirs. It can help in establishing effective patterns of injection and production wells to avoid premature waterfront break-through, and thus increase sweep efficiency and oil recovery in flooding operations. Introduction Well stimulation by hydraulic fracturing is often a prerequisite to effective oil recovery by prerequisite to effective oil recovery by waterflooding, but acceptance of this idea has been inhibited by fears that fractures would permit channeling of the displacing fluid and bypassing of oil. Donahue et al. conducted model studies of a five-spot pilot flood and found that different orientations of the pattern significantly affected the sweep efficiencies at pattern significantly affected the sweep efficiencies at breakthrough (Fig. 1). Others report that consideration must be given to the type of fracture to be formed and to the presence of natural fluid conduits in the subsurface formation of the reservoir. Hubbert and Willis, Heck, Kehle, and Dunlap report that induced fractures will be vertical and will extend in a compass direction usually dictated by the earth stresses. Their studies show that the most probable direction that will be assumed by induced fractures can be estimated with some accuracy from a study of the principal horizontal tectonic stresses. However, communication between wells or between zones and the direction of magnitude of natural fracture trends must also be delineated . The pattern of injection and production wells can then be established to make maximum economic use of the subsurface natural and induced fracture system. For the Appalachian area, considerable data have been obtained from surface studies of joints and lineaments on the direction preferred by induced hydraulic fractures and on orientation predictions. This seems to confirm the work of Heck who concluded earlier that reservoir rocks and surface rocks are jointed similarly, except that the subsurface joints are relatively closed and exist as planes of weakness. We shall describe here a field experiment designed to establish a technique for delineating the subsurface fracture system in a petroleum reservoir. Essentially, the procedure employed is an interference test that was modified by the addition of a multisensor array of pressure transducers to measure responses simultaneously and at considerable distances from the test well. The test site is adjacent to leases where joint and lineament strikes, directional permeability, and the orientations of induced hydraulic fractures were measured in the manner described by Anderson and Stahl. We shall describe the instrumentation and tests that were employed, and interpret the fracture trends from this field experiment. The Bradford Test Site Description and Location A 36-acre tract about 10 miles east of Bradford, Pa., was made available for this research by the Minard Run Oil Co. (See Fig. 2.) Open-hole completion practices were used and considerable subsurface data were practices were used and considerable subsurface data were available in the form of cores, electric logs, and wellbore impression-packer surveys. The orientation of induced hydraulic fractures was compared with surface joint measurements.

Small-Scale Fracture Density in Asmari Formation of Southwest Iran and its Relation to Bed Thickness and Structural Setting

Knowledge of the distribution of rock fractures in the Asmari limestone reservoir rock of the prolific Khuzestan oilfield belt of southwest Iran provides for a better understanding of the production mechanism. Though the high productive capacity of wells in this area has been ascribed predominantly to fracturing of the reservoir rock, quantitative work on this topic has been neglected in the past. Details of small-scale fracturing have been investigated locally on individual anticlines and regionally in Asmari limestone outcrops over an elongate area of about 2,000 sq mi (5,180 sq km) of the Zagros Mountains foothills. Fracture density has an inverse logarithmic relation to bed thickness, but it is independent of structural setting. Such findings make necessary the rejection of a theory involving a genetic relation of fractures of this scale to the folding process, at least in the area studied. The early formation of fractures is such that their orientations are related to localized irregularities, and their initiation by shock waves is suggested. Specific values for average fracture spacing in the Asmari limestone beds provide valuable data for the reservoir engineer. Fold formation by the exploitation of appropriate preexisting fracture sets enhances reservoir porosity and permeability in preferred directions.

Permeability-Porosity Patterns and Variations in Some Holocene Sand Bodies

Sandstone reservoirs are the results of long and commonly complex histories of geologic evolution. The combined processes of deposition, burial, compaction, diagenesis, and structural deformation yield final reservoir bodies of widely varied geometries, permeability-porosity characteristics, and structural configurations that are difficult to predict. In unraveling the evolution of sandstone reservoirs it is necessary to have detailed knowledge of their initial depositional characteristics and of the postdepositional modifications impressed upon them. This knowledge can provide a rational basis in predicting the characteristics of reservoir bodies away from areas of data control. Little information pertaining to the reservoir characteristics of freshly deposited sand bodi s has been available. In an API sponsored study, permeability, porosity, and textural parameters were derived from 992 oriented and undisturbed sand samples of river bars, beaches, and dunes undergoing active sedimentation. River point-bar samples have permeabilities ranging from 4 md to more than 500 darcys and average 93 darcys. Porosities in the river point-bars range from 17 to 52 percent and average 41 percent. Beach sand samples have a permeability range of 3.6 to 166 darcys and average 68 darcys. Porosities in beach sands range from 39 to 56 percent and average 49 percent. Permeability values in dune sands range from 5 to 104 darcys and average 54 darcys. Dune sand porosities range from 42 to 55 percent and average 49 percent. Permeability values in river-bar sands are extremely varied in comparison to those of beaches and dunes. In river bars, permeability decreases systematically downstream and bankward. Although of low variability, permeabilities on beaches are low on the beach faces, high on t e beach crests, and variable on the beach-berm areas. Both river-bar and beach sands have well organized directional permeabilities, parallel with the length of the bodies in river bars and perpendicular to the length of the bodies in beaches. Dunes are characterized by low variability in permeability and porosity and show no significant patterns or trends. There is greater variability within bedding and lamination packets than between them. In addition the boundary conditions between bedding and lamination packets are important factors in determining the effective reservoir characteristics of sand bodies, to the extent that a bedding unit of higher permeability completely surrounded by units of lower permeabilities will not demonstrate its ultimate through-flow capabilities, but will have an effective permeability influenced by and largely determined by the lower permeabilities of the bounding units. River-bar sand bodies have significantly different arrangement and variability between bedding units from those of beaches or dunes. The ideal relations between permeability-porosity and textural parameters that have been set forth by various authors for artificially packed particles are demonstrated only slightly by these natural sands from different depositional environments. In all three depositional environments permeability increases with increase in grain size and porosity increases with increase in grain sorting. However, in river-bar sands permeability increases as grain sorting increases and porosity increases as grain size increases, just the opposite of the relations in beach-dune sands and in the artificially packed grain experiments. The underlying cause of these deviations is the different style of grain packing in the river-bar sands.

Device for Cutting Varved Soil Samples

A device was designed and manufactured for cutting a 4.5-in. (11.4-cm) diameter varved soil sample into a 2.5-in. (6.4-cm) cubical sample for directional permeability measurements. The chief requirement was to produce cut surfaces in a layered soil which were unsmeared and untorn. The design was based on three requirements: (1) confinements of the soil during the cutting process, (2) movement of the cutting wire in the direction parallel to the soil layers and (3) small longitudinal vibratory movements of the cutting wire.

Field Examples of Automatic Transient Test Analysis

The computer technique explained here, which is useful in analyzing complex transient test data is illustrated by two field examples. In the first example the method is used to analyze data from a multiple-well interference test in an anisotropic reservoir. In the second, it is used to examine a pressure fall-off test with significant wellbore storage. Introduction Pressure transient testing can provide better average Pressure transient testing can provide better average values of in-situ reservoir permeability and porosity than core analysis or logging techniques. It can also be used to provide information about directional permeability, barriers to fluid flow, and wellbore permeability, barriers to fluid flow, and wellbore damage or stimulation. Data analysis methods include graphicals and automated techniques. The graphical techniques have the disadvantages of being restricted to relatively simple cases and of requiring subjective judgment. The automated techniques (regression and least-squares linear programming) eliminate this subjectivity. Because the automated techniques rely on digital computers, they can be used to study complicated systems and handle large quantities of data, especially data from several wells with varying flow rates. In this paper, we describe an automatic transient-test analysis technique that utilizes regression theory and the exponential integral solution to the diffusivity equation. This approach allows computer analysis of complex transient test data from systems with varying flow rates and with directional permeability. Pressure buildup, fall-off, and drawdown tests, injectivity tests, interference tests, or a combination of these tests may be analyzed. Data may be analyzed for individual wells, or simultaneously with data from other wells. To illustrate the use and value of the technique, we present the results of applying the approach to two field present the results of applying the approach to two field cases. The first field case study shows how the method can be used to analyze data from a multiple-well interference test in an anisotropic reservoir. Pressure data are from six observation wells surrounding an injection well that experienced a sporadic injection history. The irregular injection schedule would have made conventional manual data analysis extremely difficult. Automatic analysis yielded permeability values, the direction of permeability anisotropy, and an indication of reservoir permeability anisotropy, and an indication of reservoir storage capacity. These results are supported by field waterflood performance and by oriented-core data. The second case study examines a pressure fall-off test with significant wellbore storage. By accounting for the varying sand-face flow rate, automatic analysis provides a good method for calculating permeability. provides a good method for calculating permeability. This test included additional injection and shut-in periods, with pressure measured not only in the periods, with pressure measured not only in the injection well, but also in an observation well. Results from analysis of the observation-well data verify the analysis of the wellbore-storage-dominated fall-off data. Analysis Method Least-squares theory provides a rational method for selecting the parameters in any equation that result in a best fit of some observed data. JPT P. 1271