Limestone Reservoir Rock Research Articles

Geological storage of CO2 and acid gases dissolved at surface in production water

During geological CO2 storage traditionally CO2 is injected subsurface into a high permeability reservoir capped by a low permeability seal to trap the buoyant supercritical plume. Wastewater from oil and gas production is also currently disposed of by subsurface injection into suitable reservoirs, most notably in the USA and Canada. Injection of CO2 dissolved in water may both increase storage security by reducing vertical migration and enhancing dissolution and mineral trapping. There is potential for surface dissolution of CO2 into wastewater that is already being stored subsurface. CO2-water-rock reactions in different sandstone or limestone reservoir rocks with either saline coal production water or low salinity water were geochemically modelled. The geochemical potential for mineral trapping of CO2, and associated changes to pH for potential reservoirs is compared. For a mineralogically clean quartz-rich saline sandstone reservoir only 0.18 and 0.20 kg/m3 CO2 was mineral trapped as ankerite and calcite over 30 or 1000 years. Feldspars, clays and carbonate minerals were converted to kaolinite, calcite, ankerite and smectites, as pH increased to 5.65. The specific silicate minerals present controlled mineral trapping potential e.g. with an Fe-rich chlorite present rather than a clinochlore chlorite 6.3 and 6.8 kg/m3 CO2 was trapped at 30 and 1000 years respectively as siderite and ankerite. Dissolution trapping dominated in the low salinity or limestone reservoirs with minor mineral trapping. The presence of small amounts of SO2 or H2S in the CO2 stream resulted in dissolved S sequestered as elemental S, pyrite, barite, and anhydrite. The effects of low CO2 content or potential reservoir cooling induced by injection fluids were also investigated. The low pH of the injection fluid could potentially corrode legacy wellbores, one solution is a form of amendment such as liming to neutralise pH.

Origin and evolution of oilfield waters in the Tazhong oilfield, Tarim Basin, China, and their relationship to multiple hydrocarbon charging events

We conducted a chemical and isotopic study of oilfield waters from Ordovician limestone reservoirs in the Tazhong oilfield (Tarim Basin, China) to trace the origin and evolution of the waters, and to demonstrate their possible relationship with hydrocarbon charging. The elemental chemistry (Cl, Br, SO4, I, K, Na, Ca, Mg, and Sr) and multiple isotopic compositions (δD, δ18O, 87Sr/86Sr, and 129I/I) of the oilfield waters were determined. The results show that these oilfield waters contain basinal brines that infiltrated in three stages, along with a lesser contribution from meteoric water. The meteoric water appears to have infiltrated downwards during the late Silurian and Carboniferous. The earliest brine had very low I contents (<5.65 mg/L) and migrated upwards from organic-poor Cambrian to Lower Ordovician dolostones during the Late Ordovician. The second brine had high I contents (>50 mg/L), was derived from Cambrian argillaceous source rocks, and migrated upwards into Ordovician reservoirs. This stage was related to the main period of migration of crude oils out of the source rocks into reservoirs during the Silurian and Devonian. Both of these brines incorporated constant levels of fissiogenic 129I from the limestone reservoir rocks (11.8–47.0 atom/μL). Finally, brine with very low I contents, but higher 129I (106–491 atom/μL), began to migrate upwards and infiltrate reservoirs. Given the relatively high fissiogenic 129I, this stage may have occurred during the late Cenozoic, and was associated with migration of dry gas from the same source rocks. Our results, combined with those of a previous study of other oilfields in the basin, suggest that the evolutionary of oilfield waters can be used to constrain hydrocarbon accumulation events, and both of which were ultimately controlled by regional tectonism and local geological factors.

Integrated Petrophysical Modeling for a Strongly Heterogeneous and Fractured Reservoir, Sarvak Formation, SW Iran

Introducing and applying an appropriate strategy for reservoir modeling in strongly heterogeneous and fractured reservoirs is a controversial issue in reservoir engineering. Various integration approaches have been introduced to combine different sources of information and model building techniques to handle heterogeneity in geological complex reservoir. However, most of these integration approaches in several studies fail on modeling strongly fractured limestone reservoir rocks of the Zagros belt in southwest Iran. In this study, we introduced a new strategy for appropriate modeling of a production formation fractured rock. Firstly, different rock types in the study area were identified based on well log data. Then, the Sarvak Formation was divided into nine zones, and the thinner subzones were used for further fine modeling procedure. These subzones were separated based on different fracture types and fracture distribution in each zone. This strategy provided sophisticated distribution of petrophysical parameters throughout the grids of the model, and therefore, it can handle strong heterogeneity of the complex reservoir. Afterward, petrophysical parameters were used to produce an up-scaled 3D gridded petrophysical model. Subsequently, maps of petrophysical properties were derived for each zone of the Sarvak Formation. Evidences achieved in this study indicates Sarvak Formation zone 2 as the target production zone with better performance of reservoir rock and the southwestern part of the field as area of maximum porosity.

Experimental investigations of variations in petrophysical rock properties due to carbon dioxide flooding in oil heterogeneous low permeability carbonate reservoirs

Carbon dioxide has been successfully applied worldwide as an enhanced oil recovery process. Several important factors still have not been studied thoroughly. Therefore, this experimental study was carried out to investigate the variations in petrophysical reservoir rock properties of oil heterogeneous low permeability carbonate reservoirs. The main objectives of this experimental study are to investigate the effects of CO2 injection in tight limestone reservoir rocks on porosity, absolute and relative permeability, oil–water interfacial tension (IFT), reflective index, and reservoir water shielding phenomenon. Actual rock and fluid samples from an oil field in Abu Dhabi, UAE, are used to conduct this study at similar reservoir conditions of 4,000 psia and 250 °F. Oil recovery, permeability, porosity, and relative permeability were measured before and after the supercritical carbon dioxide (SC-CO2) flood to examine the effects of SC-CO2 flood on the variation in different oil and rock properties of tight composite limestone reservoir rocks. Detailed compositional analysis of initial and produced oil samples of core flood experiments were analyzed using gas chromatography to assess the mechanism of CO2 improved oil recovery. The results indicated that the application of SC-CO2 flooding under secondary and tertiary modes reduces porosity and permeability, alters relative permeability to a more water-wet condition, and reduces the oil/water IFT as a function of pore volume injected. Furthermore, the extracted components of the crude oil were also proven to be a function of injected CO2 pore volume. The applications of the attained results of this study provide much better understanding of different variation occurring in oil reservoirs under SC-CO2 injection and can be used effectively to validate and improve numerical simulation studies.

Measurement of Acid Reaction Rates with the Rotating Disk Apparatus

Abstract The authors have published several papers on the rotating disk apparatus (RDA) in recent years. The RDA is used to measure acid reaction rates, reaction order and activation energy of acidizing fluids with carbonate reservoir rock. This paper summarizes the different ways that acid reaction rates are measured, the factors that affect the results and why this is important when modelling acid stimulation treatments in the field. In particular, experimental procedures used to obtain acid reaction rates vary widely and can produce very different results. These procedures are often not well-documented in the literature. The validity of different experimental procedures are carefully compared in this paper. In addition to experimental concerns, the reactivity of reservoir rock can also vary widely. It was recently reported that the reactivity of reservoir rock toward acid is strongly affected by mineralogy and by mineral impurities. In particular, clay impurities in calcite rock were found to reduce the dissolution rate by nearly an order of magnitude. Some calcite rocks with clay content as low as 1 wt% showed acid reactivity similar to that of 100 wt% dolomite. Acidizing additives such as polymers and corrosion inhibitors have been shown to significantly affect the way that acid reacts with the reservoir rock. Introduction The rotating disk instrument is widely used in the petroleum industry for kinetic studies of the reaction of acidic fluids and chelating agents with reactive rocks(1–11). This system allows the determination of rock dissolution rate, reaction rate constants, reaction order and diffusion coefficients(1, 12). Taylor et al.(13) examined the effects of acidizing additives on acid reaction rates of calcite and dolomite rock. These additives were quaternary amines, polymer, surfactant, mutual solvent, iron chelating agents and dissolved iron (III). Taylor et al.(14, 15) examined, in detail, the relationship between acid reaction rate and rock mineralogy for a deep, dolomitic gas reservoir. Their results showed that mineralogy significantly affected acid reaction rate, and that clay contents as low as 1 wt% could reduce the apparent reaction rate of limestone reservoir rock by up to a factor of 25. There has been significant variability in acid reaction rate data of reservoir rocks(11). These variations have often been attributed to activation energies lower than obtained for pure calcite or dolomite rock(11). However, several detailed studies have contradicted this claim(8, 16). Alkattan et al.(8) showed that the dissolution rates of calcite crystals, limestones and compressed calcite powders were the same within experimental error in the bulk solution pH range of ?1 to 3 at temperatures of 25, 50 and 80 °C. The limestones contained less than 1 vol% clays, but one type of limestone (St. Maximin) did contain 16 vol% quartz. This shows that the dissolution rates of pure forms of calcium carbonate are not significantly affected by different mineralogy. Herman and White(16) showed that dissolution rates of pure forms of dolomite are not significantly affected by mineralogy. The dissolution rates of dolomites in the form of a single crystal, microcrystalline sedimentary rock and coarse-grained marble in aqueous carbonate solutions were also found to be similar(16).

Anomalous Acid Reaction Rates in Carbonate Reservoir Rocks

Summary It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock. This work is the first to show this assumption to be false in some cases, because of mineral impurities commonly found in these rocks. Trace amounts of clay impurities in limestone reservoir rocks were found to reduce the acid dissolution rate by up to a factor of 25, to make the acid reactivity of these rocks similar to that of fully dolomitized rock. A rotating disk instrument was used to measure dissolution rates of reservoir rock from a deep, dolomitic gas reservoir in Saudi Arabia (275°F, 7,500 psi). More than 60 experiments were made at temperatures of 23 and 85°C and HCl concentration of 1.0 M (3.6 wt%). Eight distinctly different rock types that varied in composition from 0 to 100% dolomite were used in this study. In addition, the mineralogy of each rock disk was examined before and after each rotating disk experiment with an environmental scanning electron microscope (ESEM) using secondary and backscattered electron imaging and energy dispersive X-ray (EDS) spectroscopy. Acid reactivity was correlated with the detailed mineralogy of the reservoir rock. It was also shown that bulk anhydrite in the rock samples was converted to anhydrite fines by the acid at 85°C, a potential source of formation damage. Introduction A study of acid reaction rates and reaction coefficients of a dolomitic reservoir rock was recently reported by Taylor et al. (2004a). In that work, it was found that reaction rates depended on mineralogy and the presence of trace components such as clays. This paper examines in detail the relationship between acid reactivity and mineralogy of a deep, dolomitic gas reservoir rock. An accurate knowledge of acid reaction rates of deep gas reservoirs can contribute to the success of matrix and acid fracture treatments. Many studies of acid stimulation treatments of Formation K, a deep, dolomitic gas reservoir in Saudi Arabia, have been published (Nasr-El-Din et al. 2001, 2002a, 2002b; Bartko et al. 2003). It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock during acidizing treatments. However, much of the reported data were obtained with pure limestones, dolomites, and marbles. These include calcite marble (CaCO3) (Lund et al. 1975; de Rozieres 1994; Frenier and Hill 2002), dolomite marble [CaMg(CO3)2] (Lund et al. 1973; Herman and White 1985), Indiana limestone (Mumallah 1991), St. Maximin and Lavoux limestones (Alkattan et al. 1998), Haute Vallée de l'Aude dolomite (Gautelier et al. 1999), Bellefonte dolomite (Herman and White 1985), San Andres dolomite (Anderson 1991), Kasota dolomite (Anderson 1991), and Khuff dolomite reservoir cores (Nasr-El-Din et al. 2002b). The effects of common acid additives on calcite and dolomite dissolution rates were reported in detail (Frenier and Hill 2002; Taylor et al. (2004b; Al-Mohammed et al. 2006). The effects of impurities such as clays on rock dissolution have not been reported.

Estimation of permeability and rock mechanical properties of limestone reservoir rocks under stress conditions by strain gauge

Petroleum engineering reservoir parameter calculations are generally performed in the absence of the overburden pressure effect. This leads to serious errors in further development of a hydrocarbon-bearing reservoir. Thus, measurements under stress conditions become important vitally. The objective is to correlate the overburden pressure and the permeability to see the overburden pressure effects on the permeability of Turkish southeastern limestone reservoir rock samples. Stress was applied to four representative limestone samples taken from southeast Turkey. In the laboratory tests, two identical core plugs from every sample were used for each application. This is why a Wheatstone Bridge with a full-bridge strain gauge method was used. A sample is inserted into a load frame and the axial load was increased. Internal friction angles and cohesion factors were determined. An exponential correlation was proposed between permeability and confining pressure. The experimental and correlated results match very accurately. The stress and permeability correlations may be useful with resistivity logs through which permeability may be measured and for stress–strain-related CBL (cement bond logs) which are used for the well bore stability during cementing applications.

Reservoir rock classification, Arab-D reservoir, Ghawar field, Saudi Arabia

ABSTRACT An integrated petrographic and petrophysical study of Arab-D carbonates in Ghawar field has provided a new reservoir rock classification. This classification provides a simple but practical method of dividing the complex carbonate rocks of the Arab-D into meaningful reservoir rock types. Each rock type has a distinct pore network as defined by porosity-permeability relationships and capillarity expressed as pore-size distributions and J-function curves. The classification divides the Arab-D carbonates into seven limestone and four dolomite rock types. The amount of matrix (lime mud) and the pore types are the primary controlling parameters for the limestones. The dolomites are divided according to their crystal texture. The seven limestone reservoir rock types are based on the values of five petrographic parameters: (1) the amount of cement, (2) the amount of matrix (lime mud), (3) the grain sorting, (4) the dominant pore type, and (5) the size of the largest molds. The amount of matrix is the most important of these five parameters. In general terms, six of these seven types fall into two broad families, A and B, each of which can then be subdivided into three members (Types I, II, and III) according to their matrix content. The first family, A, is a fairly coarse-grained, poorly sorted rock with relatively large molds. The second family, B, is a generally fine to medium-grained, well sorted rock with few or small molds. The seventh rock type contains more than 10 percent cement which modifies the pore size distribution enough to warrant a separate reservoir rock type. Each of the reservoir rock types exhibits a distinctive pore-size distribution and, in turn, Leverett J-function or capillarity. The seven types are also characterized by distinctive porosity-permeability relationships. The four dolomite reservoir rock types are classified according to their dolomite crystal texture, although stratigraphic position and porosity can also be effective in their classification. The four textures are: fabric preserving (Vfp), sucrosic (Vs), intermediate (Vi) and mosaic (Vm). The Vfp dolomite is only found in Zone 1 of the Arab-D where it is the major dolomite type. Vs dolomite occurs in dolomites with more than 12 percent porosity, Vm less than 5 percent and Vi between 5 and 12 percent. Vfp dolomites have pore systems similar to their precursor limestone but the pore systems of the other dolomite types are unique. A significant finding of this evaluation is that the micropore system in all major limestone rock types in Zones 1 and 2 (upper Arab-D) is consistently an order of magnitude larger than for the same rock types in Zones 3 and 4 (lower Arab-D). The increase in size is believed to be a result of increased leaching in the upper Arab-D. This difference suggests that rocks of similar type from the upper and lower Arab-D will behave differently in terms of their fluid flow and saturation characteristics, and will have different ultimate recoveries.

Origin of Dolostone Reservoir Rocks, Smackover Formation (Oxfordian), Northeastern Gulf Coast, U.S.A. (1)

Formation of regionally extensive dolostone reservoir rocks in the Smackover can be understood despite the possible effects of recrystallization. Geochemical and petrographic data suggest that dolomitization took place in (1) seawater-seepage, (2) reflux, (3) near-surface mixed-water, (4) shallow-burial mixed-water, and (5) deeper burial environments, which overlapped in time and space to form a platform-scale dolostone body composed of a complex mixture of dolomites. Seawater-seepage and reflux dolomitization occurred in the near surface penecontemporaneously with deposition of the Smackover and overlying Haynesville Formations. Dolomitization by seawater seepage occurred within an oolite grainstone sill which separated an intraplatform salt basin from the open sea. Seawater flowed landward through the sill in response to evaporitic drawdown of brines in the isolated intraplatform basin. Isolation of the salt basin occurred during the Oxfordian when the shoreline retreated from the Conecuh embayment. Dolomite located at the top of the Smackover enriched in {18}O suggests additional dolomitization by reflux of hypersaline brines. Reflux occurred as Buckner coastal sabkhas prograded over Smackover oolite grainstone shoreface deposits. Vugs lined with shallow-burial calcite and dolomite cements indicate flushing of the Smackover grainstone aquifer with fresh water. Freshwater intrusion probably occurred following sea level lowstands during the Late Jurassic and Early Cretaceous. Leaching in the proximal portion of the freshwater aquifer produced excellent limestone reservoir rocks in the updip Smackover. Dolomitization in the contemporaneous downdip mixed connate/freshwater zone formed dolostone reservoir rocks with depleted isotopic compositions consistent with a shallow-burial mixed-water origin.

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.

Detection and Estimation of Dead-End Pore Volume in Reservoir ROCK by Conventional Laboratory Tests

Abstract Conventional laboratory core analysis tests on samples of two limestone reservoir rocks indicate that about 20 per cent of PV is in dead-end pores. These tests (electric logging formation factor. mercury injection capillary pressure and miscible displacement) were carried out on 3/4-in. diameter test plugs. Test results show a clear difference between these samples and sandstone or homogeneous limestone reservoir rock. Although the amount of dead-end pore space can be only roughly estimated, the presence of such pore space seems clearly indicated. Pressure transient studies also show presence of dead-end PV. Although they do not give quantitative results, pressure transient data yield a reasonable estimate of the size of the neck connecting dead-end pores to the main flow channels. Introduction Equations conventionally used to describe reservoir flow behavior contain the implicit assumption that all connected pore spaces contributed to both porosity and permeability. Several authors have pointed out the changes in pressure transient behavior and in electric log interpretation that may result if this assumption is incorrect and, instead, dead-end or cul-de-sac pores are present. There is a need for laboratory tests that can detect presence of dead-end pores in core samples. With such information on hand the petroleum engineer can make more rational use of the mathematical tools now available for analysis of reservoir flow behavior. This paper describes laboratory studies designed to detect and, if possible, give a quantitative measure of dead-end PV in laboratory-size core plugs. Three reservoir rocks were used, two of which were limestones suspected of having dead- end pore spaces and a well-known sandstone, used as a comparison standard, in which there is believed to be little or no dead-end pore space. All the studies were designed to measure the natural dead-end PV; i.e., the pore space which is dead-ended because of rock structure. During multiphase flow in a rock without dead-end pores, some parts of one of the phases can become surrounded by the other, thereby giving (for certain flow behavior) an effective dead-end PV 8,9. Such behavior will not be described here. FORMATION FACTOR THEORY One of the simplest laboratory measurements which can be made on core plugs is the electric logging formation factor F. By definition: (1) where Ro is the resistivity of the core plug saturated with a saline solution of resistivity Rw. Difficulties in using this definition of F may arise when the solid framework of the rock is electrically conducting. These difficulties may be largely circumvented by using a highly conducting saline solution so that the conduction contribution of the solid is negligible. There are no useful theoretical relationships between F and the porosity phi. A widely used empirical relation is the one given by Archie: (2) where m, called the cementation factor, is expected to be a constant for a given type of rock. Pirson shows that for reservoir rocks, m varies from about 1.3 for loosely cemented sandstones to 2.2 for highly cemented sandstones or carbonate rocks. SPEJ P. 206ˆ

Petrology of Beaver Lodge Madison Limestone Reservoir, North Dakota

The Mississippian Madison limestone reservoir rock in the Beaver Lodge field, Williams County, North Dakota, was studied to determine its lithologic character and distribution of the porous zones. The reservoir is a fine- to medium-grained fragmental limestone and dolomitic limestone. Grains include fossil fragments, crystal fragments, and fecal pellets. Originally, porosity was intergranular but later it was increased by solution and dolomitization and decreased by recrystallization and cementation. There are three major, separate, porous zones in the reservoir; each zone contains lenticular streaks of porous rock which form an interfingering pattern like that of interbedded sandstone and shale. Porosity, controlled by original texture, has been increased through dolomitization by 3 to 5 times. Fracturing is most common in the finer parts of the rock, and the fracturing provides permeability connections between the porous lentils. The mineralogy is similar to that found in modern deposits on the Bahama Banks; the environment of deposition was probably similar. The porosity pattern at Beaver Lodge Mississippian limestone reservoir appears to be due partly to a sedimentary response to intermittent uplift and folding during Mississippian time.

Some Examples of Fluid Flow Mechanism in Limestone Reservoirs

Abstract The properties of limestone reservoir rocks such as the distribution anddegree of continuity of the pore systems, and the relative volumes andpermeabilities of the systems making up the complex cause large variationsbetween performance of individual limestone reservoirs and their susceptibilityto secondary recovery methods. The effects of these factors on the mechanism offluid flow cannot be adequately evaluated with presently developed concepts, laboratory data, and geological information. The observance and interpretationof the performance of individual limestone reservoirs provides, at present, themost adequate approach for evaluating the integrated effects upon performanceof the many, now immeasurable variations in the properties of limestonereservoirs. Introduction The development and application of techniques for increasing the efficiencyof oil recovery from natural reservoirs is a problem of primary importance tothe industry. During the past several years, a great deal of effort has beenexpended by the technical personnel of the industry toward the improvement ofpresent known methods of oil recovery, and evaluating the factors which controlthe susceptibility of particular reservoir types to economic application ofsecondary recovery methods. Providing adequate and accurate laboratory data onthe properties of the reservoir rock and its contained fluids, together withgood production statistics, are available, methods have been evolved forestimating with reasonable accuracy the performance of an oil reservoir undereither continued natural depletion or conditions imposed by introducingadditional displacing fluid into the reservoir from an extraneous sourcethrough the injection of gas and/or water. The susceptibility of limestone reservoirs to secondary recovery by gasinjection is very much dependent upon gas-oil relative permeabilityrelationships for the reservoir in question. In a rock formation in which theporosity is of the intergranular type such as is found in sand stones and somenonfractured dolomites, a representative sample of the pore structure can beobtained in a small core plug. In this type of reservoir, it has been shownthat relative permeability data obtained from laboratory experiments can beproperly applied to evaluate the flow relationships actually observed duringthe depletion of a reservoir. In addition, a good idea of the fraction of thereservoir which will be swept by the injected gas may be obtained from thespacing pattern used and the permeability profile of cored wells. From thesedata, it has been demonstrated that reliable estimates of performance andrecoveries under gas injection operations can be made for reservoirs in whichthe porosity is of the intergranular type. T.P. 2638

Bibliography on the Acid Treatment of Oil Wells

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