Porosity Andpermeability Research Articles

Benchmark study using a multi-scale, multi-methodological approach for the petrophysical characterization of reservoir sandstones

Abstract. This paper presents a detailed description and evaluation of a multi-methodological petrophysical approach for the comprehensive multi-scale characterization of reservoir sandstones. The suggested methodology enables the identification of links between Darcy-scale permeability and an extensive set of geometrical, textural and topological rock descriptors quantified at the pore scale. This approach is applied to the study of samples from three consecutive sandstone layers of Lower Cretaceous age in northern Israel. These layers differ in features observed at the outcrop, hand specimen, petrographic microscope and micro-CT scales. Specifically, laboratory porosity and permeability measurements of several centimetre-sized samples show low variability in the quartz arenite (top and bottom) layers but high variability in the quartz wacke (middle) layer. The magnitudes of this variability are also confirmed by representative volume sizes and by anisotropy evaluations conducted on micro-CT-imaged 3-D pore geometries. Two scales of directional porosity variability are revealed in quartz arenite sandstone of the top layer: the pore size scale of ∼0.1 mm in all directions and ∼3.5 mm scale related to the occurrence of high- and low-porosity horizontal bands occluded by Fe oxide cementation. This millimetre-scale variability controls the laboratory-measured macroscopic rock permeability. More heterogeneous pore structures were revealed in the quartz wacke sandstone of the intermediate layer, which shows high inverse correlation between porosity and clay matrix in the vertical direction attributed to depositional processes and comprises an internal spatial irregularity. Quartz arenite sandstone of the bottom layer is homogenous and isotropic in the investigated domain, revealing porosity variability at a ∼0.1 mm scale, which is associated with the average pore size. Good agreement between the permeability upscaled from the pore-scale modelling and the estimates based on laboratory measurements is shown for the quartz arenite layers. The proposed multi-methodological approach leads to an accurate petrophysical characterization of reservoir sandstones with broad ranges of textural, topological and mineralogical characteristics and is particularly applicable for describing anisotropy and heterogeneity of sandstones on various rock scales. The results of this study also contribute to the geological interpretation of the studied stratigraphic units.

Structural control on fluid flow and shallow diagenesis: insights from calcite cementation along deformation bands in porous sandstones

Abstract. Porous sandstones are important reservoirs for geofluids. Interaction therein between deformation and cementation during diagenesis is critical since both processes can strongly reduce rock porosity and permeability, deteriorating reservoir quality. Deformation bands and fault-related diagenetic bodies, here called “structural and diagenetic heterogeneities”, affect fluid flow at a range of scales and potentially lead to reservoir compartmentalization, influencing flow buffering and sealing during the production of geofluids. We present two field-based studies from Loiano (northern Apennines, Italy) and Bollène (Provence, France) that elucidate the structural control exerted by deformation bands on fluid flow and diagenesis recorded by calcite nodules associated with the bands. We relied on careful in situ observations through geo-photography, string mapping, and unmanned aerial vehicle (UAV) photography integrated with optical, scanning electron and cathodoluminescence microscopy, and stable isotope (δ13C and δ18O) analysis of nodules cement. In both case studies, one or more sets of deformation bands precede and control selective cement precipitation. Cement texture, cathodoluminescence patterns, and their isotopic composition suggest precipitation from meteoric fluids. In Loiano, deformation bands acted as low-permeability baffles to fluid flow and promoted selective cement precipitation. In Bollène, clusters of deformation bands restricted fluid flow and focused diagenesis to parallel-to-band compartments. Our work shows that deformation bands control flow patterns within a porous sandstone reservoir and this, in turn, affects how diagenetic heterogeneities are distributed within the porous rocks. This information is invaluable to assess the uncertainties in reservoir petrophysical properties, especially where structural and diagenetic heterogeneities are below seismic resolution.

A synthetic map of the north-west European Shelf sedimentary environment for applications in marine science

Abstract. Seabed sediment mapping is important for a wide range of marine policy, planning and scientific issues, and there has been considerable national and international investment around the world in the collation and synthesis of sediment datasets. However, in Europe at least, much of this effort has been directed towards seabed classification and mapping of discrete habitats. Scientific users often have to resort to reverse engineering these classifications to recover continuous variables, such as mud content and median grain size, that are required for many ecological and biophysical studies. Here we present a new set of 0.125∘ by 0.125∘ resolution synthetic maps of continuous properties of the north-west European sedimentary environment, extending from the Bay of Biscay to the northern limits of the North Sea and the Faroe Islands. The maps are a blend of gridded survey data, statistically modelled values based on distributions of bed shear stress due to tidal currents and waves, and bathymetric properties. Recent work has shown that statistical models can predict sediment composition in British waters and the North Sea with high accuracy, and here we extend this to the entire shelf and to the mapping of other key seabed parameters. The maps include percentage compositions of mud, sand and gravel; porosity and permeability; median grain size of the whole sediment and of the sand and the gravel fractions; carbon and nitrogen content of sediments; percentage of seabed area covered by rock; mean and maximum depth-averaged tidal velocity and wave orbital velocity at the seabed; and mean monthly natural disturbance rates. A number of applications for these maps exist, including species distribution modelling and the more accurate representation of sea-floor biogeochemistry in ecosystem models. The data products are available from https://doi.org/10.15129/1e27b806-1eae-494d-83b5-a5f4792c46fc.

Characterization of Reservoir Heterogeneity by Capacitance-resistance Model in Water-flooding Projects

Tedious calculations and simulations are needed to obtain an efficient production scenario and/orproper field development strategy. Capacitance-resistance model (CRM) is proved to be a fastreservoir simulation tool using just the field-available data of production and injection rates. Thisapproach sets a time-constant and a weighting factor (or well-pair connectivity parameter) betweeneach pair of injection and production wells according to their histories. In this study, we investigatedthe behavior of the CRM parameters in synthetic reservoir models with different porosity andpermeability maps. Four reservoirs are considered with different porosities and permeabilities to studytheir effects on CRM response. We defined a new parameter, named error to mean production ratio(EMPR), to analyze the CRM performance. Some fluctuations are exerted on the production data toevaluate the capability of CRM against variable production records. Porosity showed a stronger effecton CRM parameters than the permeability based on the calculated EMPR. Unstable productionhistory would result in large error which can be corrected with some smoothing techniques onvariable production data. Also, a linear trend of EMPR was obtained with the change of porosity andpermeability or a combination of the two parameters within the reservoir.

Reservoir characteristics of the Bass Islands dolomite in Otsego County, Michigan: Results for a saline reservoir CO2 sequestration demonstration

As part of a phase II plan to understand, test, and evaluate the CO2 sequestration potential for deep saline reservoirs in Michigan, a demonstration test well was completed in late 2006 in Otsego County, northern lower Michigan. The well was drilled to 3630 ft (1006 m) and open-hole logged. Selected conventional cores totaling 180 ft (55 m) were taken in the saline reservoir (Bass Islands Formation), the immediately overlying confining unit (Bois Blanc Formation), and the overlying seal (Amherstberg Formation). Additionally, 24 sidewall cores were taken in several uphole formations. The whole core was sampled every foot by drilling 2-in. (5-cm)-long and 1-in. (2.5-cm)-diameter test plugs for porosity and permeability (PP) analyses. Seventy-four horizontal plugs, 12 vertical plugs, 6 whole cores, and 17 sidewall core plugs were sent to Core Laboratories for routine PP analyses. Fifteen blue-dyed, epoxy-impregnated thin sections were made from selected PP plugs. The whole core was slabbed for examination and description of lithology, sedimentary structures, and facies characteristics. This Upper Silurian and Lower–Middle Devonian stratigraphic section was carefully examined for lithology and facies characteristics that relate to reservoir and seal properties pertinent to CO2 sequestration. The overlying primary seal (Amherstberg Formation) is a low-porosity, low-permeability limestone that is highly fossiliferous and densely cemented with calcite and chalcedony. This unit is the ultimate vertical barrier to the vertical migration of fluids. The immediately overlying confining unit (Bois Blanc Formation) is a very cherty limestone and dolostone with moderate porosity and low permeability. Some fluids may move into this unit, but very low permeability will severely restrict the vertical flow. Thin sections show abundant microporosity. The target saline reservoir interval (Bass Islands Formation) is a variably porous and permeable dolostone composed of several tidal flat cyclic packages. The Bass Islands Formation has a gross thickness of 70 ft (21 m) with a reservoir interval composed of more than 40 ft (12 m) of greater than 10% porosity and permeability zones exceeding 500 md. Average porosity over the entire Bass Islands is 12.5%. Average permeability is 22.4 md. The CO2 injection tests, using the Bass Islands section, were completed during February and March 2008. Analysis of the Bass Islands Formation in northern Michigan indicated excellent reservoir quality for injection and storage of CO2 and high-quality sealing units to prevent vertical migration. Monitoring well data conducted during and after the injection test validates preinjection reservoir simulation modeling performed at Battelle Pacific Northwest Labs using well data and rock observations from this study.

<b>Contrast in clay mineralogy and their effect on reservoir properties in sandstone formations</b>

Adigrat sandstone formation in the Blue Nile Basin is dominated by quartz arenite and subarkosic arenite, and cemented by carbonate, clay minerals and quartz overgrowths. Clay minerals in the Adigrat sandstone formation are dominated by kaolinite, illite and chlorite. Illite is the common grain-coating clay mineral. The common pore-filling minerals are kaolinite, illite and chlorite. The formation reaches a depth of 3km, which facilitated the change of kaolinite to illite. Clay minerals are the major reducer of porosity andpermeability in the Adigrat sandstone formation. The Permo-Triassic sandstones in the Ulster Basin were deposited in NE-SW trending fault-bounded asymmetrical graben. The Permo-Triassic sandstones reaches a burial depth of 1/2 km in the marginal areas and 4.5 km in the basin center. The basin underwent multiple episodes of uplift and erosion in the Upper Jurassic, and Mid-Cretaceous, and uplift and inversion in the Upper Tertiary. The difference of the clay mineralogy in the Permo-Triassic in the Ulster Basin depends upon the depositional environments, source area geology and burial history of the basin. Illite-smectite is grain coating, whereas smectite, illite-smectite, smectite-chlorite, chlorite,illite and kaolinite are the common pore-filling clay minerals in the Permo-Triassic sandstones in the Ulster Basin. Clay minerals reduced the porosity and permeability of the Permo-Triassic sandstones. KEY WORDS: Adigrat sandstone, Authigenic mineralization, Clay minerals, Diagenesis, Permo-Triassic sandstones, Reservoir characteristics Bull. Chem. Soc. Ethiop. 2008, 22(1), 41-65.

Lateral Variations in Upper Mantle Structure of the Philippine Sea Basin

The Chinkuashih-Shuinantung area is mainly composed of outcrops from theMiocene Nankang Formation.Crustal movements after the late Pliocene have ledto several high-angle faults and lifted the Shitih Formation to the surface.Duringthe Pleistocene,dacite intruded into Miocene sediments and thereafter hydrothermalgold-copper ore deposits were formed.These deposits are composed mostly of metalsulfides,including pyrite,enargite,galena,tetrahedrite,and sphalerite,togetherwith limited native gold.All these sulfides may produce acid mine drainages.Theriver bed course of the Chiufen Chi is rather close to the fault traces,indicating aclose relationship between water flow systems and tectonic movements.Water and soil samples were collected from several selected sites,includingthe upper,middle,and lower stream areas of the Chiufen Chi;along with thewest,south,and east banks of the Shuinantung Bay;in addition,mine watersdrained directly from the Penshan 5th adit and 7th adit were also collected neartheir portals.Geochemical data such as pH value,water temperature,turbidity,conductivity,dissolved oxygen,and selected ionic concentrations,were measuredlater.All samples were collected and analyzed during each season of a year.Theresults indicate that water drained from the two mine adits and the lower streamarea of the Chinfen Chi exhibit low pH values,high metal(esp.Cu and Fe)andsulfate contents,and great conductivities.The acid mine drainage effect is veryobvious,especially during the rainy season.The Transient Electro-Magnetic(TEM)method,using square loops 20 m on aside,was also applied in this area for prospecting purposes.Measured transientvoltages were inverted in terms of 1-D models.Four-layered models consistingof low-high-low-low resistivity patterns best fit the 49 coincident loop data.Theeffective exploration depth was between 5 m to 50m.Furthermore,resistivitiesmeasured along the Chiufen Chi varied with the season,indicating high porosity andpermeability in rocks underlying the study area,probably due to ore mineralization,faults or joints;on the other hand,resistivities measured along the ShuinantungBay are not affected by seasonal change,indicating a saturated aquifer underneaththe area near the sea.

Geologic Description of East Velma West Block, Sims Sand Unit, for an Enhanced Oil Recovery Project

Summary East Velma West Block, Sims Sand Unit (EVWBSSU), located in Stephens County, OK, is currently beingflooded with CO2. A detailed, quantitative, reservoirdescription was constructed for a simulation model thatwill aid in the evaluation and operation of the CO2 flood. The Sims sandstone member of the Upper-Mississippian/Lower Pennsylvanian Springer formation was deposited in a deltaic environment. Four deltaic facies are present: the delta plain, proximal and distal delta-front, present: the delta plain, proximal and distal delta-front, and abandonment phase. The delta-plain facies forms ashale barrier to vertical fluid flow between the abandonment and proximal delta-front sandstones. The proximaldelta-front facies forms the bulk of the reservoir. Porosity (16%) and permeability (70 md) in this facies are high Porosity (16%) and permeability (70 md) in this facies are high because of minor clay and cement content. The proximaldelta-front facies grades laterally downstructure into the distal delta-front facies. Authigenic clays and carbonateand silica cement have reduce porosity (14%) and permeability (30 md) in the distal delta-front sandstones. permeability (30 md) in the distal delta-front sandstones. A reservoir description was built from the geologic analysis for a four-component, three-dimensional (3D)full-field model. Reservoir zonation was based on the arrangement of deltaic facies. Porosity from gamma-ray/densitylogs was calibrated to core porosity to determine porosity in uncored wells. A linear correlation between core porosity in uncored wells. A linear correlation between core porosity and permeability was established for each facies. porosity and permeability was established for each facies. Permeability and gamma ray cutoffs were statistically Permeability and gamma ray cutoffs were statistically determined to define net pay. Vertical-to-horizontal permeability ratios were determined from measurements on permeability ratios were determined from measurements on oriented core plugs. Computer isopach maps of gross pay, net pay, porosity, and horizontal and verticalpermeability were generated for individual reservoir zones and permeability were generated for individual reservoir zones and then entered into the reservoir model. Introduction ARCO Oil and Gas Co. is conducting an enhanced-oil-recoveryprogram on EVWBSSU in Stephens County, program on EVWBSSU in Stephens County, OK. Continuous injection Of CO2 into the updip portion of the reservoir began in Sept. 1983. EVWBSSU wasdiscovered in 1949 with an estimated 220 × 10 STB[34 958 × 10 m3] of original oil in place (OOIP). Primary depletion was by gravity drainage. Crestal gas Primary depletion was by gravity drainage. Crestal gas injection for pressure maintenance began in 1962 andwater injection began in 1972. Approximately 32% ofOOIP was recovered by these methods of production. Success Of CO2 flood depends on distribution ofreservoir lithology, porosity, and permeability. Distributionand continuity Of sandstone reservoirs are controlled bydepositional environments. Clay and cement contentdetermine the subsurface distribution of porosity andpermeability. Thus the purpose of this study was to analyze permeability. Thus the purpose of this study was to analyze mineral composition and to determine the depositionalsetting of Sims sandstone. On the basis of this geologicanalysis, a reservoir description was constructed for asimulation model. Stratigraphy The Upper-Mississippian/Lower-Pennsylvanian Springerformation consists of approximately 2,500 ft [7670 m] ofalternating sandstone and shale. The Goddard formationconformably underlies the Springer formation, which isunconformably overlain by Morrowan-Age rocks. Four subsurface Springer sandstone members-indescending order, the Markham, Aldridge, Humphreys, andSims-have been defined by drilling in the westernArdmore basin. The Sims sandstone member, ranging inapparent gross thickness from 300 to 600 ft [91.4 to 182.9m], is the major oil-producing horizon within the Velmareservoir. It consists of three sandstone units: indescending order, C1, C2, and C3. Sandstones are white to buff, fine-grained, and subrounded to subangular. They gradebasinward into clay-rich sandstones and finally into shales. Approximately 250 ft [77.1 m] of shale overlies the Simssandstone member. Geologic Setting The Sims member of the Springer formation was depositedon moderately subsiding shelves in theAnadarko-Ardmore basin, which is bounded by the Arbuckle upliftto the north, by the Wichita-Criner uplift to the south, and by the Ouachita foldbelt to the east (Fig. 1). The EVWBSSU is part of the Velma reservoir, locatedin the northwestern part of the Ardmore basin. TheEVWBSSU is approximately 3.5 miles [5.6 km] long and0.75 miles [1.2 kin] wide (Fig. 2). This reservoir strikesin a southeast-northwest direction. It dips steeply (30 to60* [0.52 to 1.04 rad]) to the northeast. To the south, the EVWBSSU is bounded by an erosional unconformityand, to the north, by poor reservoir quality and a water/oilcontact (WOC). Folding and faulting of the Velma reservoir, whichoccurred in Early Pennsylvanian times during collision ofNorth American, South American, and Africancontinental masses, is postdepositional. JPT P. 1420

Study of The Field Application of Sandstone Acidizing (includes associated papers 6507 and 6555 )

In a study to determine what factors most influence sandstone acidizing andproduction response infield treatments, it was found that the mostcritical factors are mud-acid volume and treating pressure. The optimumresponse was obtained with mud-acid volumes of 125 to 200 gal/ft; the poorest treatment response occurred when acid was injectedat pressures in excess of fracturing pressure. Introduction Much of the improvement in stimulation proceduresduring recent years has come about as a result of closelyexamining field experience. Exxon Co., U.S.A., periodically examines the success of stimulation treatments as afunction of treatment design parameters and reservoircharacteristics. Such an examination was made recentlyconcerning experience gained from April through Sept.1973. Although the original survey covered acidizing, fracturing, and surfactant methods of well stimulationand involved the treatment of both sandstone andcarbonate formations, this paper describes only the resultsfound for sandstone acidizing. As the study developed, more data were examined than were available during the6-month survey period cited. In some cases, field resultsfrom Jan. 1968 through May 1974 were examined. Overall, 222 treatments from the Texas-Louisiana Gulf Coast, West Coast, and Mid-Continent areas were examined.Test data from the Mid-Continent area were too few tojustify a separate analysis. The most detailed data wereavailable for treatments along the Texas Gulf Coast -an area where the acid-mutual solvent method isextensively used. Success of sandstone acidizing was related tothe design and execution parameters of the treatment andto reservoir characteristics thought to be significant. The outcome of a treatment was judged first on apurely economic basis. A treatment was called successfulif the increase in oil production provided payout of the jobcosts within a 3-month period. This payout was based onpre-embargo oil prices and involved an oil value of$2.20/bbl after federal income tax. This criterion is morestringent than current economic conditions wouldwarrant, and some jobs ruled unsuccessful in this studywould be ruled successful if re-evaluated. The data gathered on each job in the study are shown inTable 1. The factors of most interest were the size andcomposition of each of the three phases of a standardacid-mutual solvent treatment, the manner of executionof the treatment in the field, and several reservoirparameters. The last category comprised the porosity andpermeability of the formation, the length of theperforated interval, and the depth, bottom-hole pressure, andtemperature of the formation. No effort was made toperform a detailed mineralogical analysis of theformations treated because of the time and expense involved.Manipulation of the data acquired was accomplished by aMark IV computer program. The range of the study and the names of the formationstreated are shown in Table 2. A wide range of geologicages and a broad spectrum of formation depths, temperatures, porosities, and permeabilities were considered. Depth ranged from 1,010 to 13,358 ft, formationtemperature from 95 degrees to 275 degrees F, porosity fromless than 7 to 36 percent, and formation permeabilityfrom 1 to 2,350 md. JPT P. 1289^

Sample Grading Method of Estimating Gas Reserves

Abstract A technique is presented by which well samples and core plugs of dolomiteformations are classified by microscopic examination into seven differentporosity grades. Quantitative values of porosity and permeability aredetermined for each grade by a statistical correlation of the core plug testdata with the porosity grading system. These quantitative values are applieddirectly to the grades exhibited in the well samples for the purpose ofestimating the reservoir void space for wells that were not cored. The procedure is described for estimating the gas reserves per unit area forthe South Hugoton gas field, but a reserve estimate for the field is notgiven. Introduction The miscroscopic examination of well samples and the graphic recording oftheir lithologic qualities and other distinguishing characteristics of variousgeologic formations drilled is both a science and an art of long standing andwide application. Usually the primary objective of a geologist who "sits onthe well" and examines the samples are: to identify the formation beingdrilled, determine the total depth, casing point, and completion interval. Inmost cases the porosity is described, if done at all, in general terms, suchas: trace, scattered, fine, poor, fair, medium, good, excellent, or in someother relative terms. In fields where various geologists have examined samplesand recorded observations on many wells considerable variations in lithologicterms and porosity descriptions occur unless there is primary effort toestablish uniformity of logging observations and standards of recordingobservable porosity. When an estimate of the pore volume of a reservoir is made a geologicconcept of the processes that control the magnitudes of porosity andpermeability is developed by microscopic examination of well samples. Thecharacteristics and appearances are then mentally related to rather generalquantitative units of porosity based on physical core data from the samereservoir or on such data or experience in other reservoirs that have similarqualities. The reliability of such estimates depends largely on the variationsof the lithology of the formations, the geometric properties of its voidsystem, the extent of comparisons of sample appearances with porosity data, aswell as the uniform recording of all relevant characteristics. This statementis particularly significant for dolomitized limestone formations of substantialthicknesses and heterogeneity such as the Permian Dolomites of the Hugoton gasfield. T.P. 3374

Capillary Pressures - Their Measurement Using Mercury and the Calculation of Permeability Therefrom

Abstract An apparatus is described whereby capillary pressure curves for porous mediamay be determined by a technique that involves forcing mercury under pressureinto the evacuated pores of solids. The data so obtained are compared withcapillary pressure curves determined by the porous diaphragm method, and theadvantages of the mercury injection method are stated. Based upon a simplified working hypothesis, an equation is derived to showthe relationship of the permeability of a porous medium to its porosity andcapillary pressure curve, and experimental data are presented to support itsvalidity. A procedure is outlined whereby an estimate of the permeability of drillcuttings may be made with sufficient accuracy to meet most engineeringrequirements. Introduction The nature of capillary pressures and the role they play in reservoirbehavior have been lucidly discussed by Levrett, Hassler, Brunner, and Deahl, and others. As.a result of these publications the value of determiningcapillary pressure curves for cores has come to be generally recognized withinthe oil industry. While considerable attention has been directed toward thesubject in an effort to provide a reliable method of estimating percentages ofconnate water, it has been recognized that capillary pressure data may prove ofvalue in other equally important applications. This paper describes a method and procedure for determining capillarypressure curves for porous media wherein mercury is forced under pressure intothe evacuated pores of the solids. The pressure-volume relationships obtainedare reasonably similar to capillary pressure curves determined by the generallyaccepted porous diaphragm method. The advantages of the method lie in therapidity with which the experimental data can be obtained and in the fact thatsmall, irregularly shaped samples, e.g., drill cuttings, can be handled in thesame manner as larger pieces of regular shape such as cores or permeabilityplugs. Based upon a simplified working hypothesis, a theoretical equation will bederived which relates the capillary pressure curve to the porosity andpermeability of a porous solid, and experimental data will be presented tosupport its validity. This relationship applied to capillary pressure dataobtained for drill cuttings by the procedure described provides a means forpredicting the permeability of drill cuttings. T.P. 2544

An Introductory Discussion of the Reservoir Performance of Limestone Formations

Abstract Field experience with limestone and sandstone production indicates theexistence of wide differences between the reservoir behavior of these two typesof formation. Little attention appears to have been given to the separate studyof the flow of fluids and the retention of fluids in limestones. This paperpresents data and arguments to demonstrate the existence of a difference?between the two types of formation, and urges the separate intensiveinvestigation of limestone reservoirs. All experimental data presented pertainto dolomitic limestone formations in West Texas and New Mexico. Two kinds of porous media are recognized intergranular and intermediate.Intergranular rocks are those in which the porosity and permeability aredetermined by the geometrical properties and the sorting of the sedimentaryunits; intermediate rocks, those in which there is no direct relationshipbetween grain properties and the porosity and permeability. Limestones ingeneral are intermediate media. The partial relationship between porosity andpermeability of any class of porous media is represented by an area of finiteextent and definite shape on the permeability-porosity plane. The horizontal and vertical variations of porosity and of permeability inlimestone and sandstone formations are discussed and compared. Comparisons are made of connate-water content,. the relativepermeability-saturation relationship, and. capillary phenomena in the two kindsof rocks. A number of tentative conclusions are drawn relative to the reservoirproperties of limestones; in particular,dolomitic limestones are oilbearing and apparently are oil productive in zones of permeability less than0.1 millidarcy, andprimary depletion (by gas expansion) oil saturationsmay be lower in dolomitic limestones than in sandstones. Introduction It is well known that the reservoir performance of limestones displays numerousirregularities when compared with that of sandstones, and that the departuresfrom "normal" behavior of limestones are more frequent and generallymore marked than in sandstones. This is particularly true of fracturedlimestones and those that have undergone considerable development of secondaryporosity. A review of the literature of production research published during the past ISyears reveals a startling absence of theoretical and experimentalinvestigations directed specifically toward explaining and predicting theperformance of limestone reservoirs, even though such problems as theprediction of 'water encroachment and the estimation of ultimate recoveriescontinue at the. "inspired guess" stage. By far the greater part of theexperimental data reported pertain to measurements on sandstone core samples, while the theoretical studies, almost without exception, are developed from theassumption of an ideal porous medium and therefore seldom are applicable tolimestone formations. T.P. 1791