Showing papers on "Petroleum reservoir published in 2009"

Smart Water as Wettability Modifier in Carbonate and Sandstone: A Discussion of Similarities/Differences in the Chemical Mechanisms

Abstract: Waterflooding has for a long time been regarded as a secondary oil recovery method. In the recent years, extensive research on crude oil, brine, and rock systems has documented that the composition of the injected water can change wetting properties of the reservoir during a waterflood in a favorable way to improve oil recovery. Thus, injection of “smart water” with a correct composition and salinity can act as a tertiary recovery method. Economically, it is, however, important to perform a waterflood at an optimum condition in a secondary process. Examples of smart water injection in carbonates and sandstones are: (1) injection of seawater into high temperature chalk reservoirs and (2) low salinity floods in sandstone reservoirs. The chemical mechanism behind the wettability alteration promoted by the injected water has been a topic for discussion both in carbonates and especially in sandstones. In this paper, the suggested mechanisms for the wettability modification in the two types of reservoir rocks a...

Pore-throat characterization in highly porous and permeable sandstones

Abstract: Several methods have been developed to characterize the pore spaces in sandstone reservoirs using data on the pore-throat-size distribution obtained from mercury injection tests. The Winland equation, the threshold pressure, the displacement pressure, and Pittman's equation are mostly used for this purpose to delineate the stratigraphic traps and seals. This study examines the reliability of these methods applied to the highly permeable Nubia sandstones in their type section in southern Egypt. These sandstones are composed mainly of siliceous sandstones and constitute the main Paleozoic–Cretaceous aquifers and reservoirs in Egypt. Routine core analysis and mercury injection tests were conducted to delineate the pore network characteristics for these rocks. The relationships between helium porosity and the uncorrected air permeability from the routine core analysis, and the various parameters derived from mercury injection–capillary pressure curves were established using multiple regressions. This study indicates the high reliability of the displacement pressure at 10% mercury saturation and also reveals the apex of Pittman's hyperbole at 45% mercury saturation as a complexity apex at which the pore network becomes highly chaotic. Despite the great benefits of such types of measurements, they are not commonly used because of their high cost. This study introduces a series of empirical equations for constructing a partial pore-aperture-size distribution curve from routine core analysis for the highly permeable rocks.

Petroleum reservoir porosity versus depth: Influence of geological age

Abstract: Average porosity values for the producing zones of oil and gas fields worldwide are examined as a function of the present depth for sandstone and carbonate lithologies divided into 10 groupings by reservoir depositional age (Precambrian–Silurian to Pliocene–Pleistocene). The wide variations in average reservoir porosity within each depth range reflect the extreme ranges in porosity-controlling factors such as depositional facies, early

The geology of the Barmer Basin, Rajasthan, India, and the origins of its major oil reservoir, the Fatehgarh Formation

Abstract: With the Mangala oil discovery in 2004, Cairn established the Barmer Basin of Rajasthan as a major new hydrocarbon province. Most reserves are contained in fluvial sandstone reservoirs of the Fatehgarh Formation, which probably ranges in age from Late Cretaceous to Early Paleocene. The Fatehgarh sandstones were mainly derived from reworking of Mesozoic sandstones at the northern end of the Barmer rift, but with some volcaniclastic input probably derived from Deccan volcanic rocks within and on the margins of the rift. These thick, quartz-rich, high porosity and permeability sandstones provide an excellent oil reservoir in the north of the Barmer Basin, but the increasing volcanic influence further south causes reservoir quality and thickness of net sand to deteriorate. This paper relates how the tectonic and volcanic evolution of the northwest margin of the Indian plate has influenced the depositional trends which have resulted in formation of this world class reservoir.

Method of seeking hydrocarbons in a geologically complex basin, by means of basin modeling

Abstract: A method for mapping a complex sedimentary basin is disclosed. A grid representative of the current architecture of the basin is constructed. A mechanical structural restoration is applied in three dimensions so as to reconstruct the past architectures of the basin from the current time up to a geological time t. A simulation of the geological and geochemical processes that govern the formation of a petroleum reservoir is then carried out, directly in the grids obtained from the restoration, from the geological time t to the current one. This simulation is thereafter used for mapping the sedimentary basin so as to identify zones of the basin where hydrocarbons may have accumulated.

Influences of Different Modes of Reservoir Heterogeneity on Performance and Oil Recovery of Carbon Dioxide Miscible Flooding

Abstract: Reservoir heterogeneity represents one of the most dominant factors affecting the performance of CO 2 miscible flooding and its expected oil recovery. The main goal of this study is to investigate the influence of different modes of reservoir heterogeneity on oil recovery by supercritical CO 2 miscible flooding. The investigated heterogeneity modes include: 1) different single fractured reservoirs of different inclination angles, 2) different permeability configurations of layered reservoirs, and 3) the sequence of permeability distributions in composite reservoirs. Complete reservoir rock and oil compositional analyses were performed. The minimum miscibility pressure (MMP) of oil-CO 2 was mathematically calculated using several empirical correlations and determined experimentally using slim tube tests. The core flood tests were achieved using actual fluids injected through 12 actual reservoir rock samples. Of these, four samples were of different fracturing angles as single fractured reservoirs, four samples were of different permeability configurations as layered rocks and four samples represented composite reservoirs. The slug size of supercritical CO 2 was optimized to be 0.15 PV, injected and chased by actual reservoir brine through these different simulated modes of reservoir heterogeneity. The results indicated that all different modes of reservoir rock heterogeneity have a crucial influence on oil recovery by CO 2 miscible flooding in carbonate oil reservoirs. Of note, unfractured reservoirs produced higher oil recovery by CO 2 miscible flooding than single fractured ones. An oil reservoir with a 30 degree inclination angle of single fracture produced the highest oil recovery, whereas, fractured rocks with a 45 degree fracture produced the minimum oil recovery in this category. The rock permeability sequences of medium-low-high (MLH) mode for composite reservoirs and medium-high-low (MHL) distribution mode for layered reservoirs are highly recommended for CO 2 miscible flooding. The results have proven the suitability of the CO 2 application for layered and composite heterogeneous carbonate reservoirs, however, it does not recommend this EOR process for single fractured reservoirs. The results have also shown a real impact on oil recovery of the reservoir heterogeneity mode prevailing in the reservoir under development by this EOR process.

Application of converted-wave 3D/3-C data for fracture detection in a deep tight-gas reservoir

Abstract: The deep-gas reservoirs of China's western Sichuan Basin are in Members 2 and 4 of the Upper Triassic Xujiahe Formation. These reservoirs contain mid- to large-sized gas fields like Xinchang, Hexingchang, Qiongxi, Zhongba, and Bajiaochang. The favorable geological conditions for creating these fields include abundant source rock, well-developed reservoir rock, good preservation conditions, and structural traps.

Subsurface characterization and geological monitoring of the CO2 injection operation at Weyburn, Saskatchewan, Canada

Abstract: The IEA Weyburn Carbon Dioxide (CO2) Monitoring and Storage Project analysed the effects of a miscible CO2 flood into a Lower Carboniferous carbonate reservoir rock at an onshore Canadian oilfield. Anthropogenic CO2 is being injected as part of a commercial enhanced oil recovery operation. Much of the research performed in Europe as part of an international monitoring project was aimed at analysing the long-term migration pathways of CO2 and the effects of CO2 on the hydrochemical and mineralogical properties of the reservoir rock. The pre-CO2 injection hydrochemical, hydrogeological and petrographical conditions in the reservoir were investigated in order to recognize changes caused by the CO2 flood and to assess the long-term fate of the injected CO2. The Lower Carboniferous (Mississippian) aquifer has a salinity gradient in the Weyburn area, where flows are oriented SW–NE. Hydrogeological modelling indicates that dissolved CO2 would migrate from Weyburn in an ENE direction at a rate of about 0.2 m/annum under the influence of regional groundwater flow. Baseline gas fluxes and CO2 concentrations in groundwater were also investigated. The gas dissolved in the reservoir waters allowed potential transport pathways to be identified. Analysis of reservoir fluids proved that dissolved CO2 and methane (CH4) increased significantly in the injection area between 2002 and 2003. Most of the injected CO2 exists in a supercritical state, lesser amounts are trapped in solution and there is little apparent mineral trapping. The CO2 has already reacted with the reservoir rock sufficiently to mask some of the strontium isotope signature caused by 40 years of water flooding. Experimental studies of CO2–porewater–rock interactions in the Midale Marly Unit indicated slight dissolution of carbonate and silicate minerals, followed by relatively rapid saturation with respect to carbonate minerals. Carbon dioxide flooding experiments on similar rock samples demonstrated that porosity and gas permeability increased significantly through dissolution of calcite and dolomite. Several microseismic events were recorded over a six-month period and these are provisionally interpreted as being related to small fractures formed by injection-driven fluid migration within the reservoir, as well as other oilfield operations. Experimental studies on the overlying and underlying units show similar reaction processes; however secondary gypsum precipitation was also observed. Reaction experiments were conducted with CO2 and borehole cements. The size and tensile strength of the cement blocks were unaffected, however their densities increased. Pre- and post-injection soil gas survey data are consistent with a shallow biological origin for the measured CO2 in soil gases. Isotopic (13C) data values are higher than in the injected CO2, and confirm this interpretation. No evidence for leakage of the injected CO2 to ground level has been detected. The long-term safety and performance of CO2 storage was assessed by the construction of a features, events and processes (FEP) database that provides a comprehensive knowledge base for the geological storage of CO2.

Adsorption of non-petroleum base surfactant on reservoir rock

Abstract: Surfactant loss due to adsorption on the reservoir rock is one of the major concerns in enhanced oil recovery (EOR) processes. It weakens the effectiveness of the injected slug in reducing oil-water interfacial tension (IFT) and makes the process uneconomical. In this study, an attempt is made to investigate the adsorption of Na-lignosulphonate onto the porous media of Oil India Limited (OIL) petroleum reservoir rocks. The data were interpreted from the well-known models and it was found that the Langmuir model is a good fit for the pH and brine data over the entire range of variables. Adsorption increases with NaCl concentration and decreases with increase in pH.

Storage capacity and containment issues for carbon dioxide capture and geological storage on the UK continental shelf

Abstract: Carbon dioxide (CO2) can be stored in geological formations beneath the UK continental shelf (UKCS) as a greenhouse gas mitigation option. It can be trapped in subsurface reservoirs in structural or stratigraphic traps beneath cap rocks, as a residual CO2 saturation in pore spaces along the CO2 migration path within the reservoir rock, by dissolution into the native pore fluid (most commonly brine), by reaction of acidified groundwater with mineral components of the reservoir rock, or by adsorption onto surfaces within the reservoir rock, e.g. onto the carbonaceous macerals that are the principal components of coal. Estimates of the CO2 storage capacity of oil and gas fields on the UKCS suggest that they could store between 1200 and 3500×106 t of CO2 and up to 6100×106 t CO2, respectively. Estimating the regional CO2 storage potential of saline water-bearing sedimentary rocks is resource-intensive and no UK estimates have yet taken into account all the factors that should be considered. Existing s...

Long-term Petrophysical Investigations on Geothermal Reservoir Rocks at Simulated In Situ Conditions

Abstract: In the course of stimulation and fluid production, the chemical fluid–rock equilibrium of a geothermal reservoir may become disturbed by either temperature changes and/or an alteration of the fluid chemistry. Consequently, dissolution and precipitation reactions might be induced that result in permeability damage. In connection with the field investigations at a deep geothermal doublet, complementary laboratory-based research is performed to address these effects. The reservoir is located at a depth of 4100 to 4200 m near Gros Schonebeck within the Northeast German Basin, 50 km north of Berlin, Germany. Within the reservoir horizon, an effective pressure of approximately 45 MPa and a temperature of 150°C are encountered. Furthermore, the Lower Permian (Rotliegend) reservoir rock is saturated with a highly saline Ca–Na–Cl type formation fluid (TDS ≈ 255 g/l). Under these conditions we performed two sets of long-term flow-through experiments. The pore fluid used during the first and the second experiment was a 0.1 molar NaCl-solution and a synthetic Ca–Na–Cl type fluid with the specifications as above, respectively. The maximum run duration was 186 days. In detail, we experimentally addressed: (1) the effect of long-term flow on rock permeability in connection with possible changes in fluid chemistry and saturation; (2) the occurrence and consequences of baryte precipitation; and (3) potential precipitations related to oxygen-rich well water invasion during water-frac stimulation. In all substudies petrophysical experiments related to the evolution of rock permeability and electrical conductivity were complemented with microstructural investigations and a chemical fluid analysis. We also report the technical challenges encountered when corrosive fluids are used in long-term in situ petrophysical experiments. After it was assured that experimental artifacts can be excluded, it is demonstrated that the sample permeability remained approximately constant within margins of ±50 % for nearly six months. Furthermore, an effect of baryte precipitation on the rock permeability was not observed. Finally, the fluid exchange procedure did not alter the rock transport properties. The results of the chemical fluid analysis are in support of these observations. In both experiments the electrical conductivity of the samples remained unchanged for a given fluid composition and constant p-T conditions. This emphasizes its valuable complementary character in determining changes in rock transport properties during long-term flow-through experiments when the risk of experimental artifacts is high.

Petroleum system in deepwater basins of the northern South China Sea

Abstract: The northern South China Sea margin has experienced a rifting stage and a post-rifting stage during the Cenozoic. In the rifting stage, the margin received lacustrine and shallow marine facies sediments. In the post-rifting thermal subsidence, the margin accumulated shallow marine facies and hemipelagic deposits, and the deepwater basins formed. Petroleum systems of deepwater setting have been imaged from seismic data and drill wells. Two kinds of source rocks including Paleogene lacustrine black shale and Oligocene-Early Miocene mudstone were developed in the deepwater basin of the South China Sea. The deepwater reservoirs are characterized by the deep sea channel fill, mass flow complexes and drowned reef carbonate platform. Profitable capping rocks on the top are mudstones with huge thickness in the post-rifting stage. Meanwhile, the faults developed during the rifting stage provide a migration path favourable for the formation of reservoirs. The analysis of seismic and drilling data suggests that the joint structural and stratigraphic traps could form giant hydrocarbon fields and hydrocarbon reservoirs including syn-rifting graben subaqueous delta, deepwater submarine fan sandstone and reef carbonate reservoirs.

Using 3-D Seismic Volumetric Curvature Attributes to Identify Fracture Trends in a Depleted Mississippian Carbonate Reservoir: Implications for Assessing Candidates for CO2 Sequestration

Abstract: The widespread Western Interior Plains aquifer system of the central United States provides a significant potential for sequestration of CO2 in a deep saline formation. In Kansas, several severely depleted Mississippian petroleum reservoirs sit at the top of this aquifer system. The reservoirs are primarily multilayered shallow-shelf carbonates with strong water drives. Fluid flow is strongly influenced by natural fractures, which were solution enhanced by subaerial karst on a Mississippian–Pennsylvanian regional unconformity. We show that three-dimensional (3-D) seismic volumetric reflector curvature attributes can reveal subtle lineaments related to these fractures. Volumetric curvature attributes applied to a 3-D seismic survey over a Mississippian oil reservoir in Dickman field, Ness County, Kansas, reveal two main lineament orientations, N45E and N45W. The northeast-trending lineaments parallel a down-to-the-north fault at the northwestern corner of the seismic survey and have greater length and continuity than the northwest-trending lineaments. Geologic analysis and production data suggest that the northeast-trending lineaments are related to debris-, clay-, and silt-filled fractures that serve as barriers to fluid flow, whereas the northwest-trending lineaments are related to open fractures that channel water from the underlying aquifer. The discrimination of open versus sealed fractures within and above potential CO2 sequestration reservoirs is critical for managing the injection and storage of CO2 and for evaluating the integrity of the overlying seal. Three-dimensional seismic volumetric curvature helps to locate fractures and is a potentially important tool in the selection and evaluation of geologic sequestration sites.

The Evolution Characteristics of Palaeo-Uplifts in Tarim Basin and Its Exploration Directions for Oil and Gas

Abstract: Based on the structure interpretation and the analysis of regional tectonic setting controlling on oil,it indicates that multi-cycle tectonic movement and migration of palaeo-uplifts had occurred in Tarim basin.It includes six stages of evolution:the commence of basement lift in the Precambrian,the formation before the end of Early Ordovician,completion before the end of Ordovician,modification during Silurian-Devonian,local regulation during the end of Permian,tectonic station during Mesozoic.The evolution of palaeo-uplift was characterized by multiple epoches,inheritance,migration and modification and formed three large Palaeozoic palaeo-uplifts which were dominated by the lower Palaeozoic carbonate,including the central uplift,the northern uplift and the southwestern uplift.The uplifts forming in the Palaeozoic controlled the hydrocarbon distribution in the platform-basin region.The polycyclic tectonic movements together with three stages of hydrocarbon migration and accumulations,resulted in the vertical overlap of the producing layer,reservoir rock,multi-phase and multi-type of oil reservoir,and then formed a complex petroleum accumulation zone in the palaeo-uplifts.The slopes of the Palaeozoic uplifts are the main exploration orientations in Tarim basin.The Paleao-uplifts evolution analysis showed that there exists a large Palaeozoic uplift which submerged in the late Himalayan in Migaiti slope,southwestern Tarim basin.The Ordovician karst reservoir and the Carboniferous mud cap rock formed a high-quality reservoir-cap assemblage in the uplift with the Hercynian hydrocarbon and oil accumulation and the Himalayan gas accumulation.Thus,the southwestern uplift is a potential exploration domain after the discovery of the big oil/gas fields in the uplift in the north and centrel of Tarim basin.

Impact of Poroelastic Response of Sandstones on Geothermal Power Production

Abstract: During geothermal power production using a borehole doublet consisting of a production and injection well, the reservoir conditions such as permeability k, porosity π and Skempton coefficient B at the geothermal research site Gross Schoenebeck/Germany will change. Besides a temperature decrease at the injection well and a change of the chemical equilibrium, also the pore pressure Pp will vary in a range of approximately 44 MPa ±10 MPa in our reservoir at −3850 to −4258 m depth. This leads to a poroelastic response of the reservoir rocks depending on effective pressure P eff (difference between mean stress and pore pressure), resulting in a change in permeability k, porosity π and the poroelastic parameter Skempton coefficient B. Hence, we investigated the effective pressure dependency of Flechtinger sandstone, an outcropping equivalent of the reservoir rock via laboratory experiments. The permeability decreased by 21% at an effective pressure range from 3 to 30 MPa, the porosity decreased by 11% (P eff=6 to 65 MPa) and the Skempton coefficient decreased by 24% (p eff=4 to 25 MPa). We will show which mechanisms lead to the change of the mentioned hydraulic and poroelastic parameters and the influence of these changes on the productivity of the reservoir. The most significant changes occur at low effective pressures until 15 to 20 MPa. For our in situ reservoir conditions p eff=43 MPa a change of 10 MPa effective pressure will result in a change in matrix permeability of less than 4% and in matrix porosity of less than 2%. Besides natural fracture systems, fault zones and induced hydraulic fractures, the rock matrix its only one part of geothermal systems. All components can be influenced by pressure, temperature and chemical reactions. Therefore, the determined small poroelastic response of rock matrix does not significantly influence the sustainability of the geothermal reservoir.

Reservoir Rock Typing in a Carbonate Reservoir- Cooperation of Core and Log Data: Case Study

Abstract: Reservoir characterization is one of the most challenging subjects in Carbonate reservoirs. In this study Flow Zone Index, Winland and initial water saturation methods were used to classify rock typing in an Iranian oil field located in the southeastern region. In addition, the predicted initial water saturation along with log and core data was used for capillary pressure estimation. The studied field is a Cretaceous fractured oil bearing reservoir composed of tightly packed limestone characterized by high porosity but poor permeability with a thickness of 55-65 meters throughout the reservoir. The matrix permeabilities and porosity are in the range of 0.01-150 md and 5-40 percent respectively. The oil gravity is 21.5 degree API. Conventional Core data were first used to define the rock types for the cored intervals in which nine district rock types were defined. Furthermore, the FZI (Flow Zone Index) log was also generated based on the permeability which was obtained from FMI (Full-bore Formation Micro Imager) and porosity logs of cored and un-cored intervals. In addition, SLMP (Stratigraphic Modified Lorenz) plots were generated for the purpose of identifying flow zone and barriers in each well. Also, Winland method was also used for the same purpose. The results of SLMP were consistent with Winland result and FZI. The Scanning Electro Microscopy Photomicrographs of the obtained rock type were studied and found to be consistent with the finding of this work. Further, the available initial water saturations obtained from log data were classified in three groups and found to consistent with FZI and Winland methods. Based on the DRT (District Rock Type) obtained from the FZI method a correlation between initial water saturation from the log and DRT was developed for the purpose of initial water saturation prediction. The generated data was used for the capillary pressure and relative permeability estimation. The generated capillary pressure and relative permeability were consistent with available scale data and provided sufficient Pc curve for the uncored intervals.

Method for accurately evaluating targets containing oil gas in clastic rock basin

Abstract: The invention relates to a geophysical oil gas prospecting method which is capable of accurately evaluating targets containing oil gas in clastic rock basin and based on resistivity and induced polarization effect and comprises the specific steps of collecting data from a target area, processing the collected data on time domain and frequency domain, obtaining all-time apparent resistivity and phase curve, drawing a plane anomaly chart of polarization effect, and comparing the chart with the anomaly mode of an oil gas reservoir to determine oil-bearing trap as well as the position border of the oil reservoir and accurately recognize the favorable targets containing oil gas. The invention adopts a high-precision artificial source time frequency deep sounding method for sounding the solid change of electric properties from shallow to deep, including resistivity R and polarizability IP, thus being capable of accurately recognizing the favorable targets containing oil gas and further improving the success ratio of drilling.