Showing papers on "Petroleum reservoir published in 2010"

Sandstones and Sandstone Reservoirs

Abstract: About 50% of all petroleum reservoirs are sandstones; outside the Middle East, carbonate reservoirs are less common and the percentage is even higher. The most important reservoir properties are porosity and permeability, but pore geometry and wetting properties of the mineral surfaces may also influence petroleum production. Sandstones provide reservoirs for oil and gas, but also for groundwater which is a fluid that is becoming increasingly valuable. Sandstones are deposited in many different sedimentary environments by marine, fluvial and eolian (wind) processes.

Shallow‐lacustrine sand‐rich deltaic depositional cycles and sequence stratigraphy of the Upper Triassic Yanchang Formation, Ordos Basin, China

Abstract: Shallow‐lacustrine delta deposits of the Upper Triassic Yanchang Formation form the most important petroleum reservoir sandstone units in the Ordos Basin, China. Recent hydrocarbon exploration and outcrop studies demonstrated that shallow‐lacustrine sand‐rich deltas developed extensively along the gentle flanks and central part of the basin. The vertical succession of facies indicates that the Yanchang Formation records the entire lacustrine life cycle of the Late Triassic Ordos Basin. Four third‐order transgressive–regressive cycles and two larger shallow‐lacustrine deltaic cycles have been recognized. A process‐based depositional model, derived in part from the modern Ganjiang delta in Poyang Lake, China, is used to infer the origins of the sand‐rich lacustrine delta deposits. Slow basin subsidence, abundant sediment supply, autocyclic processes and a hydrologically open (overfilled) lake setting were the four main controls on the development of basin‐wide sand‐rich deltaic sequences. Recognition that inter‐connected delta‐plain sand bodies lying above the lower sequence boundary of the Yanchang Formation act as important migration pathways for oil, gas and other basin fluids, aids in exploration for stratigraphic and diagenetic traps in the delta plain area.

Evolution of the Petrophysical and Mineralogical Properties of Two Reservoir Rocks Under Thermodynamic Conditions Relevant for CO2 Geological Storage at 3 km Depth

Abstract: Injection of carbon dioxide (CO2 ) underground, for long-term geological storage purposes, is considered as an economically viable option to reduce greenhouse gas emissions in the atmosphere. The chemical interactions between supercritical CO2 and the potential reservoir rock need to be thoroughly investigated under thermodynamic conditions relevant for geological storage. In the present study, 40 samples of Lavoux limestone and Adamswiller sandstone, both collected from reservoir rocks in the Paris basin, were experimentally exposed to CO2 in laboratory autoclaves specially built to simulate CO2 -storage-reservoir conditions. The two types of rock were exposed to wet supercritical CO2 and CO2 -saturated water for one month, at 28 MPa and 90°C, corresponding to conditions for a burial depth approximating 3 km. The changes in mineralogy and microtexture of the samples were measured using X-ray diffraction analyses, Raman spectroscopy, scanning-electron microscopy, and energy-dispersionspectroscopy microanalysis. The petrophysical properties were monitored by measuring the weight, density, mechanical properties, permeability, global porosity, and local porosity gradients through the samples. Both rocks maintained their mechanical and mineralogical properties after CO2 exposure despite an increase of porosity and permeability. Microscopic zones of calcite dissolution observed in the limestone are more likely to be responsible for such increase. In the sandstone, an alteration of the petrofabric is assumed to have occurred due to clay minerals reacting with CO2 . All samples of Lavoux limestone and Adamswiller sandstone showed a measurable alteration when immersed either in wet supercritical CO2 or in CO2 -saturated water. These batch experiments were performed using distilled water and thus simulate more severe conditions than using formation water (brine).

Determination of oil saturation in reservoir rock using paramagnetic nanoparticles and magnetic field

Abstract: Methods for detection of the presence and distribution of oil in subsurface formation are described herein. The present invention involves injection of an aqueous dispersion of the nanoparticles into the potentially oil containing subsurface formation, followed by a remote detection of the oscillation responses of the nanoparticles in the oil/water interfaces in the reservoir rock by applying magnetic field.

Montney Fracturing-Fluid Considerations

Abstract: The Montney gas reservoir has become a critically important component of current western Canadian gas supply and offers exciting future potential. However, this reservoir often presents variable and unique stimulation challenges. Unlike reservoirs that display little water sensitivity, such as the U.S. Barnett Shale and possibly the Muskwa in the Northeastern British Columbia Horn River Basin, recovery of water-based fluids in the Montney can be a key consideration in achieving economic production rates. The use of water-based fracturing fluids in low-permeability reservoirs can result in loss of effective frac half-length caused by phase trapping associated with the retention of the introduced water-based fluid to the formation. This problem is increased by the water-wet nature of most tight-gas reservoirs (where no initial liquid-hydrocarbon saturation is or ever has been present) because of the strong spreading coefficient of water in such a situation. The retention of increased water saturation (Sw) in the pore system after the injection of water-based completion fluids can restrict the flow of produced gaseous hydrocarbons, such as methane. Capillary pressures of 10 MPasy—20 MPa, or much higher, can be present in low-permeability formations at low-water saturation levels. Inability to generate sufficient capillary-drawdown force using the natural reservoir-drawdown pressure can result in extended fluid-recovery times or permanent loss of effective fracture half-length. Furthermore, use of water in subnormally saturated reservoirs, where much of the connate water has been removed by long-term evaporation effects associated with gas migration, might also reduce permeability and associated gas flow through a permanent increase in Sw of the reservoir. Secondary costs, such as rig time for swabbing, can add to the negative economic impact. The Montney is found to be a dry-gas reservoir in some areas, transitioning to an oil reservoir in other areas. Because of this, it would not be surprising to encounter retrograde condensate production through transition areas. In such a case, if sufficient drawdown pressure is applied to reduce reservoir pressure below the dewpoint, liquid hydrocarbons might condense from the produced gas phase, resulting in two-phase flow and potential trapping of the hydrocarbon liquid phase. Also, some areas of the upper Montney exhibit reservoir pressures in the 30 MPa range, whereas other areas exhibit lower pressures in the 17 MPa—21 MPa range. The same drawdown on a lower-pressured reservoir could therefore result in condensate condensing from the gas phase, where it would not have in the higher-pressured reservoir. If a third aqueous fracturing fluid is introduced, three-phase flow might occur. The resulting reduced relative permeability to gas might drastically reduce production rates. Also, emulsion-formation potential exists, which could present an additional reduction in fluid flow and recovery. Choice of fracturing fluid must be carefully determined for each area of the Montney, balancing economics with production. It is important to always keep in mind that key reservoir properties can vary dramatically in the Montney, as a function of both geographic location and depth. This paper presents laboratory test results of regained methane permeability vs. drawdown pressure and contact time with Montney core under representative reservoir conditions.

Bayes linear uncertainty analysis for oil reservoirs based on multiscale computer experiments.

Abstract: Reservoir simulators are important and widely-used tools for oil reservoir management. These simulators are computer implementations of high-dimensional mathematical models for reservoirs, where the model inputs are physical parameters, such as the permeability and porosity of various regions of the reservoir, the extent of potential faults, aquifer strengths and so forth. The outputs of the model, for a given choice of inputs, are observable characteristics such as pressure readings, oil and gas production levels and so forth, for the various wells in the reservoir.

Data Assimilation of Coupled Fluid Flow and Geomechanics Using the Ensemble Kalman Filter

Abstract: Summary In reservoir history matching or data assimilation, dynamic data, such as production rates and pressures, are used to constrain reservoir models and to update model parameters. As such, even if under certain conceptualization the model parameters do not vary with time, the estimate of such parameters may change with the available observations and, thus, with time. In reality, the production process may lead to changes in both the flow and geomechanics fields, which are dynamically coupled. For example, the variations in the stress/strain field lead to changes in porosity and permeability of the reservoir and, hence, in the flow field. In weak formations, such as the Lost Hills oil field, fluid extraction may cause a large compaction to the reservoir rock and a significant subsidence at the land surface, resulting in huge economic losses and detrimental environmental consequences. The strong nonlinear coupling between reservoir flow and geomechanics poses a challenge to constructing a reliable model for predicting oil recovery in such reservoirs. On the other hand, the subsidence and other geomechanics observations can provide additional insight into the nature of the reservoir rock and help constrain the reservoir model if used wisely. In this study, the ensemble-Kalman-filter (EnKF) approach is used to estimate reservoir flow and material properties by jointly assimilating dynamic flow and geomechanics observations. The resulting model can be used for managing and optimizing production operations and for mitigating the land subsidence. The use of surface displacement observations improves the match to both production and displacement data. Localization is used to facilitate the assimilation of a large amount of data and to mitigate the effect of spurious correlations resulting from small ensembles. Because the stress, strain, and displacement fields are updated together with the material properties in the EnKF, the issue of consistency at the analysis step of the EnKF is investigated. A 3D problem with reservoir fluid-flow and mechanical parameters close to those of the Lost Hills oil field is used to test the applicability.

Porosity prediction from seismic attributes of the Ordovician Trenton-Black River groups, Rochester field, southern Ontario

Abstract: This article integrates three-dimensional (3-D) seismic attributes and log data to determine porosity distribution of the Ordovician Trenton-Black River groups within the Rochester field, southern Ontario. The rocks are composed of tight limestone, parts of which were dolomitized to form porous reservoir rock. Previous studies of the Trenton-Black River dolomite reservoirs have indicated a close relationship between faulting and reservoir development, but few published studies have attempted to examine these relationships using 3-D seismic data. This study explores the stratigraphy and structure of the Rochester fault-related dolomite reservoir using 3-D seismic data and neural networks to predict porosity. By predicting porosity using seismic attributes, vertical and lateral distributions of porosity that can be used to guide development and exploration drilling for optimal hydrocarbon recovery were obtained. The sites of highest porosity were found to be along and within the fault zones. Faults extending from the basement into overlying Paleozoic rocks are composed of several short-plane, vertical, and subvertical fault segments. However, some of these faults appear to have originated and died within the Paleozoic rocks; they cannot be traced to the basement because of little or no offset where they penetrate the basement. Although the five identified attributes are considered important in exploration for fault-related dolomite reservoirs, the single most important attribute to employ is the amplitude envelope because the other attributes are mathematically related to it. Furthermore, the sags that are seen in the Rochester field are due to the combined effects of low-velocity pushdown and faulting. Methods and results presented in this study can be used to explore and develop fault-related dolomite reservoirs elsewhere in similar geologic settings.

"Dynamic trap":A main action of hydrocarbon charging to form accumulations in low permeability-tight reservoir

Abstract: In low permeability-tight reservoir,fluid filtration belongs to the non-Darcy flow. Only when the pressure gradient comes to the starting pressure gradient,can the filtration occur. Overpressure is a predominant dynamic force for hydrocarbon migration and accumulation in low permeability-tight reservoir,and "dynamic trap" is the most important action for hydrocarbons overpressure-charged into low permeability-tight reservoirs to form accumulations and also a three-dimensional space for hydrocarbons to be relented and accumulated. "Dynamic trap" is quite different from the conventional trap with mid-high permeability reservoir such as structural trap,stratigraphic trap and lithologic trap. The difference shows not only in charging dynamic force,filtration way,but also in oil-gas-water relation,trap shape and distribution. Advantages to form a "dynamic trap" are believed as sources and reservoirs are superimposed or interbedded in large scale,overpressures of hydrocarbon generation can act on reservoirs next to sources and hydrocarbons migrate in short distance in a pore-fracture network,which finally lead to the formation of large-scale continuous hydrocarbon-bearing interval. The "dynamic trap" ,located in the superimposition part of the source "sweet point" and the reservoir "sweet point" ,is the most easliy to form unconventional reservoirs. The presentation of the "dynamic trap" concept hopes to supply new thinking for enriching petroleum geology theory,deepening hydrocarbon accumulation's classification and prospecting unconventional hydrocarbon accumulations.

Gravity-assisted steam flooding exploitation method for heavy layer common heavy oil reservoir

Abstract: The invention is a steam assisted gravity flooding exploitation method to exploit a thick normal viscous oil reservoir. In a thick normal viscous oil reservoir, manners of vertical well gas injection, and horizontal well production, or horizontal well gas injection and horizontal well production are adopted. For an oil reservoir block, which is developed in a vertical-well way, if the well-layoutmanner combining a vertical well and a horizontal well is used, a horizontal production well can be drilled along the lower section of a known oil layer of the reservoir block to make a gas injectionvertical well be above a horizontal well. The production well and the gas injection well huff and puff simultaneously for 2 to 4 periods, the gas injection well and the production well form a thermalcommunication, or the oil layer pressure is reduced to 3-4MPa, and the gas injection well is transferred for gas injection and the production well for production and exploitation; or the gas injection well and the production well have formed a thermal communication, and the injection well is transferred for gas injection and the production well for production and exploitation, after the newly-drilled production well huff and puff for one period and the pollution near the well is cleared away. The invention can bring the sweeping effect of the displacing fluid in both the vertical and the horizontal directions into play, promote the spreading scope of the driving fluid, and increase the crude oil recovery rate of the thick normal viscous oil reservoir.

Geologic assessment and injection design for a pilot CO2-enhanced oil recovery and sequestration demonstration in a heterogeneous oil reservoir: Citronelle Field, Alabama, USA

Abstract: CO2 pilot injection studies, with site-specific geologic assessment and engineering reservoir design, can be instrumental for demonstrating both incremental enhanced oil recovery and permanent geologic storage of greenhouse gases. The purpose of this paper is to present the geologic and reservoir analyses in support of a field pilot test that will evaluate the technical and economic feasibility of commercial-scale CO2-enhanced oil recovery to increase oil recovery and extend the productive life of the Citronelle Oil Field, the largest conventional oil field in Alabama (SE USA). Screening of reservoir depth, oil gravity, reservoir pressure, reservoir temperature, and oil composition indicates that the Cretaceous-age Donovan sand, which has produced more than 169 × 106 bbl in Citronelle Oil Field, is amenable to miscible CO2 flooding. The project team has selected an 81 ha (200 ac) 5-spot test site with one central gas injector, two producers, and two initially temporarily abandoned production wells that are now in production. Injection is planned in two separate phases, each consisting of 6,804 t (7,500 short tons) of food-grade CO2. The Citronelle Unit B-19-10 #2 well (Permit No. 3232) is the CO2 injector for the first injection test. The 14-1 and 16-2 sands of the upper Donovan are the target zones. These sandstone units consist of fine to medium-grained sandstone that is enveloped by variegated mudstone. Both of these sandstone units were selected based on the distribution of perforated zones in the test pattern, production history, and the ability to correlate individual sandstone units in geophysical well logs. The pilot injections will evaluate the applicability of tertiary oil recovery to Citronelle Field and will provide a large volume of information on the pressure response of the reservoirs, the mobility of fluids, time to breakthrough, and CO2 sweep efficiency. The results of the pilot injections will aid in the formulation of commercial-scale reservoir management strategies that can be applied to Citronelle Field and other geologically heterogeneous oil fields and the design of similar pilot injection projects.

A Fully-Coupled Geomechanics and Flow Model for Hydraulic Fracturing and Reservoir Engineering Applications

Abstract: In this paper we present a practical fullycoupled geomechanics and flow model for application to hydraulic fracturing, especially in tight gas reservoirs, and other reservoir engineering applications. The mathematical formulation is consistent with conventional finitedifference reservoir simulation code to incl ude any number of phases, components and even thermal problems. In addition, the propagation of strain displacement front as a wave, and the relevant changes in stress with time, can be tracked through the wave component of the geomechanics equations. We show the development of an efficient finitedifferenc e computer code for rock deformation including thermal and wave propagation effects. The numerical approach chosen uses two different control volumes—one for fluid and heat flow and another one for rock deformation. The ultimate goal is to provide a tool to assess the effect of pore pressure, cooling or heating the reservoir, and propagation of a strain wave resulting from hydraulic fracturing on the reservoir rock frame. This information is crucial for determining the effect of shear stress on opening or closing of natural fractures during creation of hydraulic fractures, and changes in shearand compressionalwave velocities for seismic imaging purposes. A specific application of the product of this research is to simulate fracture propagation, gel cleanup and water block issues in hydraulic fracturing. The modeling results indicate significant change in shear stresses near hydraulic fractures as a result of hydraulic fracture face displacement perpendicular to the fracture face and not as much from pore pressure change because the filtrate does not travel very far into the reservoir. Similarly, temperature change effects are also very significant in changing stress distribution.

Coupling hydrocarbon degradation to anaerobic respiration and mineral diagenesis: theoretical constraints.

Abstract: The diagenetic mineral assemblages in petroleum reservoirs control the formation fluid pH and pCO2. Anaerobic biodegradation of petroleum is controlled by the transfer of electrons from reduced organic species to inorganic, redox sensitive, aqueous and mineral species in many cases through intermediates such as H2 and CH3COO ) . The terminal electron accepting reactions induce the dissolutionor precipitation of the same minerals that control the ambient pH and pCO2 in petroleum reservoirs. In this study, we develop a model for anaerobic biodegradation of petroleum that couples the production of acetate and H2 to ‘late stage’ diagenetic reactions. The model reveals that the principal terminal electron accepting process and electron donor control the type of diagenetic reaction, and that the petroleum biodegradation rate is controlled through thermodynamic restriction by the minimum DG required to support a specific microbial metabolism, the fluid flux and the mineral assemblage. These relationships are illustrated by modeling coupled microbial diagenesis and biodegradation of the Gullfaks oil reservoir. The results indicate that the complete dissolution of albite by acids generated during oil biodegradation and the corresponding elevated pCO2 seen in the Gullfaks field are best explained by methanogenic respiration coupled to hydrocarbon degradation and that the biodegradation rate is likely controlled by the pCH4. Biodegradation of Gullfaks oil by a consortium that includes either Fe 3+ -reducing or SO 2� 4 -reducing bacteria cannot explain the observed diagenetic mineral assemblage or pCO2. For octane, biodegradation, not water washing, was the principal agent for removal atfluid velocities <20 m Myr )1 .

Computer simulation of reservoir depletion and oil flow from the Macondo well following the Deepwater Horizon blowout

Abstract: This report describes the application of a computer model to simulate reservoir depletion and oil flow from the Macondo well following the Deepwater Horizon blowout. Reservoir and fluid data used for model development are based on (1) information released in BP’s investigation report of the incident, (2) information provided by BP personnel during meetings in Houston, Texas, and (3) calibration by history matching to shut-in pressures measured in the capping stack during the Well Integrity Test. The model is able to closely match the measured shut-in pressures. In the simulation of the 86-day period from the blowout to shut in, the simulated reservoir pressure at the well face declines from the initial reservoir pressure of 11,850 pounds per square inch (psi) to 9,400 psi. After shut in, the simulated reservoir pressure recovers to a final value of 10,300 psi. The pressure does not recover back to the initial pressure owing to reservoir depletion caused by 86 days of oil discharge. The simulated oil flow rate declines from 63,600 stock tank barrels per day just after the Deepwater Horizon blowout to 52,600 stock tank barrels per day just prior to shut in. The simulated total volume of oil discharged is 4.92 million stock tank barrels. The overall uncertainty in the simulated flow rates and total volume of oil discharged is estimated to be ±10 percent. Background The computer simulation described in this report was undertaken to supplement the work of the Flow Rate Technical Group, a group of scientists and engineers led by U.S. Geological Survey (USGS) Director Marcia McNutt to estimate the flow of oil from the Macondo well following the Deepwater Horizon blowout on April 20, 2010. Much of the work of the Flow Rate Technical Group was carried out prior to July 15, 2010, the date when the Macondo well was shut in to begin the Well Integrity Test. The computer simulation described in this report was carried out to analyze the shut-in pressure data obtained during the Well Integrity Test in order to gain additional knowledge of the Macondo well and the oil reservoir. Simulation results of particular interest include (1) the assessment of reservoir depletion resulting from oil flow during the 86 days from blowout to shut in, (2) the estimate of oil flow rate from the well, and (3) the estimate of total volume of oil discharged. A significant amount of data used in the development of the reservoir model described in this report were provided by BP personnel at meetings in Houston, Texas, during late June to early August 2010. Much of these data are considered proprietary and by Government regulation cannot be released. Although the proprietary data were included in the draft version of this report for USGS technical peer review, they are not included in this final release version in accordance with Government regulation. Reservoir Model Reservoir Geometry and Conditions The Macondo well produces oil from an oil reservoir known as M56. According to the BP investigation report of the Deepwater Horizon blowout (BP, 2010, Appendix W, p. 17, fig. 1.6), the M56 oil reservoir consists of three oil-producing sand layers. The top of the reservoir is penetrated by the Macondo well at a depth of approximately 18,000 ft below sea surface. The combined pay thickness of the three oil-producing sand layers is approximately 90 ft. The initial reservoir pressure is 11,850 pounds per square inch (psi). The reservoir temperature is approximately 240°F. As the bubble point of the oil in the reservoir is approximately 6,500 psi (BP, 2010, Appendix W, p. 11), the reservoir is believed to be under single-phase (liquid oil) condition. Table 1 shows the reservoir and fluid properties used in the model. However, property values are not given in this report owing to their proprietary nature. To construct the reservoir model, the bulk volume of reservoir containing the oil is estimated by ) 1 ( w o b S B V V    , (1) where Vb is the bulk volume of reservoir containing the oil [L], Vo is the volume of original oil in place [L], B is the formation volume factor [dimensionless],

System węglowodorowy z gazem ziemnym w łupkach-północnoamerykańskie doświadczenia i europejskie perspektywy

Abstract: Shale gas hydrocarbon system—North American experience and European potential. m 3 A b s t r a c t . The last two decades witnessed a significant progress in understanding unconventional hydrocarbon systems, exploration and developments in technology, which led to substantial increase of tight gas and shale gas production. This progress occurred mainly in USA, where unconventional gas production currently stands for ~50 % of annual domestic gas production, and it is forecast to increase to more than 60 % in 2016. Recoverable shale gas resources of USA and Canada are estimated at present for at least ~20 trillion m3 (~750 Tcf). Shale gas is a unique hydrocarbon system in which the same rock formation is a source rock, reservoir rock and seal (Figs. 2, 3). Gas field often appears continuous at a regional scale and does not requires hydrocarbon trap (Fig. 3). For development of shale gas, a high TOC contents (>1–2 %) is required for relatively thick formation (>30–70 m). High thermal maturity is essential for gas generation (>1.1–1.3 % Ro), and relatively low depth of burial (3500–4500 m) is necessary for commercial gas production. Gas is accumulated in isolated pores or adsorbed by organic matter (Fig. 5). Gas exploitation requires dense grid of wells with horizontal intervals and multiple fracturing. Shale gas is currently produced in several basins in USA and Canada. American success in unconventional gas production led to intensive shale gas and tight gas exploration across the world, with Europe being one of the priorities (Fig. 7). At the current stage, a couple of European sedimentary basins were selected as the major shale gas exploration targets. This includes predominantly the Lower Jurassic shale in the Lower Saxony Basin in Germany, the Alum shale in Scania (Southern Sweden), and to a lesser degree, the South-Eastern Basin in France with its Lower Jurassic and Lower to Upper Cretaceous shales, the Paris Basin in France with the Lower Jurassic shale, the Upper Jurassic shale in the Vienna Basin, the Lower Cretaceous Wealden shale in England, the Bodensee Trough in SW Germany with the Permian-Carboniferous shale, and the cenozoic Mako Trough in Hungary. In Europe the most intense exploration for shale gas is currently being carried out in Poland. The major target in that exploration is the Lower Palaeozoic shale at the East European Craton (Baltic and Lublin–Podlasie Basin), mainly the Upper Ordovician and/or Lower Silurian graptolitic shale (Fig. 8) (Poprawa & Kiersnowski, 2008; Poprawa, 2010). For that formation, Wood Mackenzie and Advanced Resources International estimated recoverable gas resources as equal to 1,400 mld m 3 and to 3,000 mld m 3 , respectively. Also the Lower Carboniferous shale of the south-western Poland (area of Fore-Sudetic Homocline; Fig. 8) could potentially accumulate gas, however in this case a limitation to potential for shale gas is a complex tectonic setting. Other black shale formations in Poland appear to have lower potential for shale gas exploration due to insufficient thermal maturity, low TOC, or low thickness.

Heavy Oil and Bitumen Recovery Using Radiofrequency Electromagnetic Irradiation and Electrical Heating: Theoretical Analysis and Field Scale Observations

Abstract: Heavy-oil and bitumen recovery from difficult geological media such as deep, heterogeneous and high shale content sands and carbonates, and oilshale reservoirs requires techniques other than conventional thermal and miscible injection methods. Materials in oil reservoirs (formation water, crude oil, oil-water emulsions, bitumen and their components like resins, asphaltenes, and paraffin) are non-magnetic dielectric materials with low electrical conductivity. If the electromagnetic field can be created to change these properties, electro-thermo controlled hydrodynamics could improve the displacement and recovery of heavyoil/bitumen. This paper deals with the recovery improvement of heavy-oil/bitumen by Radio-Frequency (RF) Electromagnetic (EM) radiation. The RF-EM fields in the form of waves can penetrate deeply enough from fractions of a meter to several hundred meters into oil and gas containing reservoirs to generate heat and eventually improve recovery mainly due to the reduction of oil viscosity. The recovery mechanisms and the dynamics of the RF-EM heating process were analyzed for several field scale applications in Russia. In the Yultimirovskaya tar sand deposits, RF-EM energy was transmitted from the RF-EM generator, located at the surface, into the formation by a coaxial system of the well pipes. Another field example analyzed was the RF-EM stimulation process in several wells of the Mordovo-Karmalskaya tar sands performed in the 1980s. It was observed that the formation was heated to the temperature which was sufficient for injection of oxidant (air) to initiate fire flooding. Then, a mathematical model of this process was presented with a sample exercise. Some data needed for this exercise were obtained from the field tests evaluated. Field tests proved the efficiency of the RF-EM stimulation of heavy oil / bitumen deposits with low water cut values (in operating production wells with water cut <30% on early field development stages). Numerical simulations suggest that bottomhole temperature and heat/mass transfer effects in the reservoir can be controlled by setting the output performance of the RF generator and by the difference between the reservoir and bottom-hole pressure. Introduction Applying radio-frequency electromagnetic energy (RF-EM) into heavy-oil reservoirs is an unconventional stimulation method. The RF-EM radiation generates a volume source of heat in the reservoir rock. Due to dielectric absorption in the medium, the EM energy transforms into thermal energy, and the resulting heat reduces the viscosity of the reservoir fluids. Results of RF-EM treatment experiments were well documented in numerous studies (Chakma and Jha, 1992; Kasevich et al., 1994; Nigmatulin et al., 2001; Ovalles et al., 2002). Theoretical aspects of heavy-oil production were covered by Abernethy (1976), Islam et al. (1991), Sahni et al. (2000), Sayakhov et al. (2002), and Carrizales et al. (2008). Several other studies investigated the heat and mass transfer processes in heavy oil reservoirs stimulated by EM radiation (Sayakhov et al., 1998; Kovaleva and Khaydar, 2004; Kovaleva et al., 2004; Davletbaev et al., 2008 and 2009). A number of other investigations proposed analytical models of lab experiments (Hiebert et al., 1986; Ovalles et al., 2002).

Characteristics of Formation Damage and Variations of Reservoir Properties during Steam Injection in Heavy Oil Reservoir

Abstract: Steam stimulation and steam flooding are two kinds of effective processes of enhanced oil recovery for a heavy oil reservoir. But steam can lead to severe and permanent formation damage due to interactions between injected fluids and reservoir rock and liquids. This article presents the laboratory studies undertaken to evaluate the influence of fluid composition, temperature, salinity, pH, dissolution and transformation of minerals, and asphalt deposition on formation damage during steam injection. The degree of damage during steam injection is observed to be dependent on pH and temperature. The technology of casting samples micrographs and scanning electron micrographs is employed to study the variations of reservoir properties after steam injection in each experiment. The mechanisms of formation damage and the characteristics of reservoir property variations are analyzed in heavy oil reservoirs during steam stimulation or steam flooding. The results show that the solubilities of rock and clay i...

Model Structure Analysis of Model-based Operation of Petroleum Reservoirs

Abstract: The demand for petroleum is expected to increase in the coming decades, while the production of petroleum from subsurface reservoirs is becoming increasingly complex. To meet the demand petroleum reservoirs should be operated more efficiently. Physics-based petroleum reservoir models that describe the flow in subsurface porous media can play an important role here. In this thesis possibilities are investigated to determine on one hand models with a complexity that is suitable for model-based operation (i.e. the relevant dynamic processes can be adequately described), and on the other hand models that only contain parameters that can be validated by measurements (in this thesis the pressure and phase-rate measurements in the wells). The most relevant dynamics of the model are determined by the controllability and observability properties. These indicate that reservoir models behave as models of much lower order than the currently used models, and that reduced-order reservoir models should focus for fixed well positions on correctly modeling the fluid front(s). In the second part identifiability and structural identifiability have been quantified and used to determine which (physical) model parameters can be reliably estimated from measurement data. From the analysis it was concluded that the parameters of reservoir models are not identifiable from production measurements and that they are largely based on qualitative geological information. Pressure measurements only contain information about grid block permeabilities in an area close to the wells in which is measured, and phase-rate measurements contain after water breakthrough only information about grid block permeabilities in the area between the injection and production wells. This supports the need to use information of other measurement types, such that better model-based decisions can be taken to make the operation of petroleum reservoirs more efficient.

Carbon dioxide (CO2) sequestration in oil and gas reservoirs and use for enhanced oil recovery (EOR)

Abstract: It is frequently said that oil and gas reservoirs are likely to be the first category of geological formation where carbon dioxide (CO2) shall be injected for greenhouse gas sequestration on a large scale, if sequestration proves feasible. Carbon dioxide is injected into comparatively few reservoirs at the present time. It is estimated, however, that 80% of oil reservoirs worldwide might be suitable for CO2 injection to enhance oil recovery. Enhanced oil recovery operations with CO2 have been limited by the availability and cost of CO2, but not necessarily candidate reservoirs. The problem of co-optimizing oil production and CO2 storage differs dramatically from current gas injection practice because of the cost–benefit difference due to the purchase cost of CO2 for enhanced recovery projects. When low-cost CO2 becomes widely available, injection into a wider range of reservoirs is foreseen, with the objective of maximizing the amount of CO2 left in the reservoir at abandonment. In addition to discussion of the conventional oil reservoir setting, we demonstrate, using laboratory experiments, the applicability and potential of low-permeability unconventional hydrocarbon reservoirs to store significant volumes of CO2.

The Structure and Hydrocarbon Traps of Sedimentary Basins

Abstract: The concept of plate tectonics offers a useful framework for structural geological analysis on all relevant scales in petroleum geology, from regional in the exploration stage, to local in the reservoir evaluation and production stages. This is natural, because the principal geological stress systems are ruled by processes in the deep earth like mantle convection and lithosphere subduction, the secondary effects of which are manifested at the base of the lithosphere and along plate margins. Based on these concepts, the basic dynamics of the lithosphere can be quantified, which is a prerequisite for the evaluation and calculation of the state of stress at any point. As seen in the perspective of the petroleum structural geologist, understanding and quantifying the stress situation at the plate margins is a prerequisite for understanding the state of stress in any basin system and in any reservoir.

The Immobility of CO2 in Marine Sediments Beneath 1500 Meters of Water

Abstract: Injecting liquid CO2 into deep-sea sediments below ca. 3 km of seawater has been suggested for the permanent storage of anthropogenic CO2. At the pressures and temperature found below 3 km of seawater, CO2 becomes denser than seawater and so is likely to remain permanently sequestered in the sediment. Deepwater engineering, however, is expensive and seawater depths of greater than 3 km are often only reached far from shore. Here, we consider the less expensive alternative of injecting CO2 into marine sediments at depths shallower than required for denser-than-seawater CO2 storage. We compare the mobility of liquid CO2 that has been injected into deep-sea reservoirs with the mobility of supercritical CO2 that has been injected into geologically equivalent (i.e., identical porosity, permeability, and effective stress) reservoirs with terrestrial pressure and temperature conditions. We demonstrate that buoyant liquid CO2 with a density of about 90 % that of seawater is sufficiently immobile that it can be considered trapped by gravity and capillarity. In contrast, supercritical CO2 under typical terrestrial conditions is highly mobile and only trapped by the appropriate confining layer in either a structural or stratigraphic trap. As a result of its very high mobility under terrestrial conditions, CO2 injected in an unconfined formation would spread beneath the confining layer to produce a large flat cylindrical-shaped plume of pure-phase CO2. In contrast, the less mobile CO2 in a typical deep-sea reservoir produces a spherical-shaped plume, resulting in a pure-phase-CO2 footprint that is much smaller than the pure-phase-CO2 footprint formed in the confined-terrestrial reservoir.

Investigation into the reliability of predictive pore-scale modeling for siliciclastic reservoir rocks

Abstract: The prediction of petrophysical and multiphase flow properties from direct pore-scale modeling has received a lot of attention in recent years. Although successful results have been reported for a number of outcrop and reservoir rocks, no exhaustive study has been performed to verify the consistency of such predictions across a wide range of rocks. Consequently, uncertainties prevail about the reliability of pore-scale modeling results for complex rocks such as those encountered in the petroleum industry. In the present work, an integrated pore-scale modeling approach was applied to 28 siliciclastic reservoir rock samples from six different fields and seven different formations from the Norwegian continental shelf (NCS). The reservoir rocks have a clay fraction of up to 0.19 and well to moderately sorted grain size distributions. The samples span almost four orders of magnitude in permeability (5mD to 20D) and nearly three decades of porosity (0.14 to 0.43). For each sample, a 3D model of the rock was constructed based on thin section analysis and geological process based modeling. Conventional and special core analysis data were available and considered during the modeling process. Predicted petrophysical properties include porosity and absolute permeability. Absolute permeability was computed using Lattice-Boltzmann simulations. Primary drainage and waterflood relative permeabilities were determined from two-phase oil-water flow simulations on the pore network representation of the 3D rock model. Flow simulation input parameters were set according to expected wettability conditions. The predicted results are compared with a large number of measured data obtained by different experimental methods and with observed field trends. Very good agreement is obtained between pore-scale modeling derived properties and available experimental data throughout the studied data set. Computed results also capture observed cross-property correlations, such as porosity vs. permeability and end point relative permeability vs. residual saturation. Deviations from the experimental data are explained in terms of sample heterogeneity, detailed pore-scale observations, and reliability of the experimental method. It is concluded that the applied integrated pore-scale modeling approach yields reliable and consistent data for siliciclastic rocks within the investigated porosity (0.14 to 0.43) and permeability (5mD to 20D) range and under weakly water-wet to weakly oil-wet conditions.

Prediction of Volumetric Sand Production and Stability of Well-bore in a Niger-Delta Formation

Abstract: Nigeria’s Niger-Delta province has been identified as one petroleum system- The tertiary Niger-Delta (Akata-Agbada) petroleum system. Almost all the petroleum resources currently are produced from the sandstone species within the Agbada formation. Also turbidite sand in the upper Akata formation is a potential target in deepwater offshore and currently producing interval onshore. This paper presents a mathematical model to simulate sand production from petroleum reservoir subject to an open-hole completion. A coupled reservoir-geo-mechanical model was used to predict the volumetric sand production and associated wellbore stability. The model is based on mixture theory with erosion. The Representative Elementary Volume (REV) composes of five phases - solid matrix, fluidized solids, oil, water, and gas phase was chosen. The model also incorporates the reservoir drawdown pressure, rock failure criteria, rock types and field condition. Analytical solution of sand displacement processes is also highlighted. Results show that the magnitude of sand production is strongly affected by the flow rate, the confining pressure, the pressure drawdown and the fluid viscosity. The determined ratio of the productivity index to the saturation of the fluidized solid can be correlated to determine reservoir formation type during sand production, and predicting the wellbore stability. The model has a higher degree of validity for light and medium crude oil flow which possesses moderate lubricating properties, and therefore erosion of sand particles during production highly depends on flow rate.