Showing papers on "Petroleum reservoir published in 2014"

An Integrated Framework for Optimizing CO2 Sequestration and Enhanced Oil Recovery

Abstract: CO2-enhanced oil recovery (CO2-EOR) is a technique for commercially producing oil from depleted reservoirs by injecting CO2 along with water. Because a large portion of the injected CO2 remains in place, CO2-EOR is an option for permanently sequestering CO2. This study develops a generic integrated framework for optimizing CO2 sequestration and enhanced oil recovery based on known parameter distributions for a depleted oil reservoir in Texas. The framework consists of a multiphase reservoir simulator coupled with geologic and statistical models. An integrated simulation of CO2–water–oil flow and reactive transport is conducted, followed by a global sensitivity and response surface analysis, for optimizing the CO2-EOR process. The results indicate that the reservoir permeability, porosity, thickness, and depth are the major intrinsic reservoir parameters that control net CO2 injection/storage and oil/gas recovery rates. The distance between injection and production wells and the sequence of alternating CO2...

Life in the slow lane; biogeochemistry of biodegraded petroleum containing reservoirs and implications for energy recovery and carbon management

Abstract: Our understanding of the processes underlying the formation of heavy oil has been transformed in the last decade. The process was once thought to be driven by oxygen delivered to deep petroleum reservoirs by meteoric water. This paradigm has been replaced by a view that the process is anaerobic and frequently associated with methanogenic hydrocarbon degradation. The thermal history of a reservoir exerts a fundamental control on the occurrence of biodegraded petroleum and microbial activity is focussed at the base of the oil column in the oil water transition zone that represents a hotspot in the petroleum reservoir biome. Here we present a synthesis of new microbiological, geochemical and biogeochemical data that expands our view of the processes that regulate deep life in petroleum reservoir ecosystems and highlights interactions of a range of biotic and abiotic factors that determine whether petroleum is likely to be biodegraded in situ, with important consequences for oil exploration and production. We also discuss the role of microbial processes for energy recovery in the future and how this fits within the broader socioeconomic landscape of energy futures.

The significance of hydrothermal alteration zones for the mechanical behavior of a geothermal reservoir

Abstract: The occurrence of hydrothermally altered zones is a commonly observed phenomenon in brittle rock. The dissolution and transformation of primary minerals and the precipitation of secondary minerals affect rocks in terms of mechanics, stress conditions, and induced seismicity. The present study investigates commonly observed phenomena of hydrothermal alteration and observations at the geothermal site of Soultz-sous-Forets, which are related to the occurrence of hydrothermal alteration. Geomechanical observations at Soultz are interpreted on the basis of synthetic clay content logs, which are created from borehole logging data, and which identify clay in hydrothermally altered zones. It is shown that hydrothermal alteration results in a reduction of the frictional strength of the reservoir rock. Weak zones can act as stress-decoupling horizons, which locally perturb the stress field and affect the evolution of the microseismic cloud. For the first time, it is shown on a reservoir scale that large magnitude seismic events are restricted to unaltered granites, whereas in clay zones, only small magnitudes are observed. It is demonstrated that clay-rich zones foster the occurrence of aseismic movements on fractures. Secondary mineral precipitation during hydrothermal alteration has a great effect on the geomechanical properties of a geothermal reservoir. The identification of such zones is a first step towards understanding the relation between alteration and mechanical processes inside a reservoir and can help in reducing induced seismicity during hydraulic stimulation of a reservoir.

Downhole fluid analysis and asphaltene science for petroleum reservoir evaluation.

Abstract: Petroleum reservoirs are enshrouded in mysteries associated with all manner of geologic and fluid complexities that Mother Nature can inspire. Efficient exploitation of petroleum reservoirs mandates elucidation of these complexities; downhole fluid analysis (DFA) has proven to be indispensable for understanding both fluids and reservoir architecture. Crude oil consists of dissolved gases, liquids, and dissolved solids, known as the asphaltenes. These different fluid components exhibit fluid gradients vertically and laterally, which are best revealed by DFA, with its excellent precision and accuracy. Compositional gradient analysis falls within the purview of thermodynamics. Gas-liquid equilibria can be treated with a cubic equation of state (EoS), such as the Peng-Robinson EoS, a modified van der Waals EoS. In contrast, the first EoS for asphaltene gradients, the Flory-Huggins-Zuo (FHZ) EoS, was developed only recently. The resolution of the asphaltene molecular and nanocolloidal species in crude oil, which is codified in the Yen-Mullins model of asphaltenes, enabled the development of this EoS. The combination of DFA characterization of gradients of reservoir crude oil with the cubic EoS and FHZ EoS analyses brings into view wide-ranging reservoir concerns, such as reservoir connectivity, fault-block migration, heavy oil gradients, tar mat formation, huge disequilibrium fluid gradients, and even stochastic variations of reservoir fluids. New petroleum science and DFA technology are helping to offset the increasing costs and technical difficulties of exploiting ever-more-remote petroleum reservoirs.

Relationship between porosity and permeability with stress using pore volume compressibility characteristic of reservoir rocks

Abstract: Effective stress is one of the most important parameters which strongly affects pore volume compressibility curve, which is used in assessing the reservoir rock properties. It causes change in porosity as well as permeability of the reservoir rocks. In the present study, pore volume compressibility characteristics of the reservoir rocks at different effective stresses were used to derive the relationship of porosity and permeability with the effective stress. To this end, analytical processes for deriving the porosity–stress and permeability–stress relationships are discussed in relation to the reservoir rocks. As a result, a porosity–stress formulation is proposed which is in good agreement with the experimental data. Also, two formulas are proposed for permeability–stress relationship; one on the base of Kozeny–Carman permeability–porosity model and the other one is based on a differential form of permeability–porosity relationship. After calibrating the required coefficients for one sandstone and three limestones, it was concluded that the first permeability–stress model is the upper bound correlation while the latter is the lower bound. Furthermore, it is shown that the latter has better agreement to the real experimental data of the sansdstone samples, while the first one is close to the experimental observations from limestone samples. Also, it is concluded that structure of pores is a key factor on permeability–stress relationship, so that there is a significant difference between the experimental data and the proposed relationship for a limestone sample with vuggy pore spaces.

Experimental and numerical investigations on CO 2 injection and enhanced gas recovery effects in Altmark gas field (Central Germany)

Abstract: The feasibility of CO2 storage and enhanced gas recovery (EGR) effects in the mature Altmark natural gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO2 as well as reservoir simulation studies to evaluate the CO2 wellbore injectivity and displacement efficiency of the residual gas by the injected CO2. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO2 has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO2 injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO2 gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO2 volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO2 will be maximized. The migration/extension of CO2 varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO2 extension and pressure propagation suggested no breakthrough of CO2 at the prospective production well during the 3-year injection period studied.

Generation and evolution of oolitic shoal reservoirs in the Permo-Triassic carbonates, the South Pars Field, Iran

Abstract: Ooid grainstone is the main reservoir rock in the Permo-Triassic Dalan and Kangan formations (Khuff equivalents) in many gas fields of the Persian Gulf and neighbouring areas. Ooids with a dominant aragonite mineralogy accumulated in a series of linear shoals and sand banks parallel to the shoreline, on the shallow parts of a vast epeiric carbonate platform. On the basis of the sequence stratigraphic analysis, these reservoir facies mainly developed during relative sea-level rises and increases in accommodation space. Integrated petrographic and geochemical studies reveal that ooid grainstone was altered through a complex diagenetic history, largely controlled by water chemistry, as a result of relative sea-level fluctuations. Two main types of ooid grainstone are the result: dolomitised grainstone or type H and oomouldic grainstone or type M. Dolomitised grainstone is commonly associated with the transgressive systems tract (TST), and developed under hypersaline conditions. In comparison, oomouldic grainstone is predominant in the early highstand systems tract (HST), which was affected by intensive meteoric diagenesis. Petrophysical study indicates that the reservoir properties of these rocks are largely a function of diagenesis. On the basis of their dominant pore types and diagenetic modifications, the ooid grainstone facies of the studied formations are grouped into five reservoir rock types. The spatial and temporal distribution of these rock types and their diagenetic evolution can be predicted within the sequence stratigraphic framework. Among these rock types, porosity has been greatly enhanced by dolomitisation and dissolution in the dolomitised grainstone (DG) and oomouldic grainstone (MG). On the other hand, it has been reduced by cementation and compaction in tightly cemented and compacted grainstones (CEG and COG rock types). The primary porosity has been relatively well preserved in grainstone with interparticle porosity (IPG rock type). The later porosity reduction during burial was also controlled by rock type. This study shows that despite the great burial depth, a significant amount of porosity is still preserved in oomouldic grainstone.

Petroleum system analysis of the Khatatba Formation in the Shoushan Basin, north Western Desert, Egypt

Abstract: The Middle Jurassic Khatatba Formation is an attractive petroleum exploration target in the Shoushan Basin, north Western Desert, Egypt. However, the Khatatba petroleum system with its essential elements and processes has not been assigned yet. This study throws the lights on the complete Khatatba petroleum system in the Shoushan Basin which has been evaluated and collectively named the Khatatba-Khatatba (!) petroleum system. To evaluate the remaining hydrocarbon potential of the Khatatba system, its essential elements were studied, in order to determine the timing of hydrocarbon generation, migration and accumulation. Systematic analysis of the petroleum system of the Khatatba Formation has identified that coaly shales and organic-rich shales are the most important source rocks. These sediments are characterised by high total organic matter content and have good to excellent hydrocarbon generative potential. Kerogen is predominantly types II–III with type III kerogen. The Khatatba source rocks are mature and, at the present time, are within the peak of the oil window with vitrinite reflectance values in the range of 0.81 to 1.08 % Ro. The remaining hydrocarbon potential is anticipated to exist mainly in stratigraphic traps in the Khatatba sandstones which are characterised by fine to coarse grain size, moderate to well sorted. It has good quality reservoir with relatively high porosity and permeability values ranging from 1 to 17 % and 0.05–1,000 mD, respectively. Modelling results indicated that hydrocarbon generation from the Khatatba source rocks began in the Late Cretaceous time and peak of hydrocarbon generation occurred during the end Tertiary time (Neogene). Hydrocarbon primarily migrated from the source rock via fractured pathways created by abnormally high pore pressures resulting from hydrocarbon generation. Hydrocarbon secondarily migrated from active Khatatba source rocks to traps side via vertical migration pathways through faults resulting from Tertiary tectonics during period from end Oligocene to Middle Miocene times.

Application of seismic attributes and spectral decomposition for reservoir characterization of a complex fluvial system: Case study of the Carbonera Formation, Llanos foreland basin, Colombia

Abstract: Hydrocarbon exploration in the Llanos foreland basin of eastern Colombia has traditionally focused on structural traps. However, in the past decade, the country’s oil demand has generated an increased interest in exploration for stratigraphic traps. We integrated 700 km2 of 3D seismic data volumes with eight wells in the Central Llanos area to assess the reservoir potential of the fluvial channel deposits of the Late Eocene–Oligocene Carbonera Formation in the Casanare Province. Distinguishing nonproductive, mud-filled channels from productive sand-filled channels is of economic importance for hydrocarbon exploration because both channel types can exhibit a similar seismic character. Our interpretation of the fluvial sandstone and the reservoir identification was based on 3D seismic attributes, including coherence, curvature, and spectral decomposition, and the analysis of fluvial geomorphology. Analysis of stratal slices through coherence, isofrequency amplitude cubes, and curvature cubes reveal...

Estimation of permeability of a sandstone reservoir by a fractal and Monte Carlo simulation approach: a case study

Abstract: . Permeability of a hydrocarbon reservoir is usually estimated from core samples in the laboratory or from well test data provided by the industry. However, such data is very sparse and as such it takes longer to generate that. Thus, estimation of permeability directly from available porosity logs could be an alternative and far easier approach. In this paper, a method of permeability estimation is proposed for a sandstone reservoir, which considers fractal behavior of pore size distribution and tortuosity of capillary pathways to perform Monte Carlo simulations. In this method, we consider a reservoir to be a mono-dispersed medium to avoid effects of micro-porosity. The method is applied to porosity logs obtained from Ankleshwar oil field, situated in the Cambay basin, India, to calculate permeability distribution in a well. Computed permeability values are in good agreement with the observed permeability obtained from well test data. We also studied variation of permeability with different parameters such as tortuosity fractal dimension (Dt), grain size (r) and minimum particle size (d0), and found that permeability is highly dependent upon the grain size. This method will be extremely useful for permeability estimation, if the average grain size of the reservoir rock is known.

Experimental Investigation of Surfactant Flooding in Shale Oil Reservoirs: Dynamic Interfacial Tension, Adsorption, and Wettability

Abstract: The recovery factor of waterflood operations is constrained by formation geology and pore trapping mechanisms. This is particularly important for unconventional reservoirs such as shale oil with ultra-low permeability and porosity. Surfactant flooding can be used in these reservoirs to reduce oil trapping and increase sweep efficiency due to a reduction in interfacial tension and wettability alteration. On the other hand, a major concern with surfactant flooding is the adsorption of surface-active agents on the reservoir rock leading to loss of chemicals. In this study, the behavior of a non-ionic surfactant was investigated in order to enhance oil recovery from a producing shale oil reservoir using reservoir crude oil and rock samples. In the preliminary experiments, phase behavior tests were performed in the presence of reservoir shale rock to monitor micro-emulsion stability. The critical micelle concentration (CMC) of this surfactant was determined by both surface tension measurements and spectroscopy. Dynamic interfacial tensions (IFT) and contact angles (CA) of the non-ionic surfactant in brine/oil/shale systems were then measured by the rising/captive bubble technique using a state-of-the-art IFT/CA apparatus at reservoir conditions (6840 psi and 116℃) for different surfactant concentrations (0.005 to 0.5 wt%). The amount of surfactant adsorption from surfactant-brine solutions onto crushed shale rocks were measured using UV-Vis spectroscopy at different surfactant concentrations. The data could be fit to a Langmuir type adsorption isotherm. The adsorption parameters were determined and results were compared and discussed. This work shows that the non-ionic surfactant is able to reduce the reservoir oil-brine IFT from its original value (27 mN/m) down to 15 mN/m while exhibiting minimal adsorption on the shale surface.

Tectonic Evolution of the Leshan-Longnvsi Paleo-uplift and Reservoir Formation of Neoproterozoic Sinian Gas

Abstract: Taking Dengying Formation of Neoproterozoic Sinian of Leshan-Longnvsi paleo-uplift as a target, relationship between the evolution of paleo-uplift and hydrocarbon accumulation has been studied.It has undergone several periods of tectonic movements during the Leshan-Longnvsi paleo-uplift:Tongwan movement,including episode I and episodeⅡ,controlling the development of paleo-karsting;Caledonian movement,controlling the formation of embryonic paleo-uplift;Hercynian movement,Indo-China movement and Yanshanian movement,controlling the oil and gas reservoir process.During these periods,paleo-uplift generally inherently developed,while paleo-uplift axis continuously migrated from northwest to southeastward and finally set in Himalayan.Based on the researches on fluid inclusions and burial history,it was recognized that there were three key generation or expulsion periods,i.e.,Silurian,early Triassic and JurassicCretaceous sedimentary stages,respectively.There were seven periods during the Sinian Dengying Formation:initial charge,hydrocarbon stagnation,secondary charge,formation,migration and cracking of paleooil reservoir,and formation of gas reservoir.Combined numerical simulation with oil and gas exploration, gas reservoir modeling of Dengying Formation in Sinian was established.Gas reservoir group were distributed as a cluster block in the slope of paleo-uplift where Well Gaoshi1existed.They showed as layered distribution in plane.The slope of paleo-uplift was an important gas exploration area.And it was also recognized that petroleum system of neoproterozoic in China would play a significant role for oil prospecting.

Heavy Oil Production by Electromagnetic Heating in Hydraulically Fractured Wells

Abstract: The results of numerical studies of heavy oil production by radio frequency–electromagnetic heating (RF–EM) from hydraulically fractured low-permeability reservoirs are presented. The fluid flow to a single vertical high-conductivity fracture is considered assuming that electrical and thermal properties of the reservoir rock and fluid-saturated fracture are the same. Comparative analysis is performed for the cases of heavy oil recovery by RF–EM radiation with hydraulic fracturing and “cold” production. Modeling of the combined multi-stage method and economic analysis for different RF–EM generator powers, differential pressure between the well and formation, and the fracture conductivity showed that the method is most effective for wells with “short” and low-conductivity hydraulic fractures.

Petroleum reservoir engineering

Abstract: The branch of petroleum engineering concerned with predicting the optimum economic recovery of oil o…

Stratification developing method for complex fault block thin oil reservoir

Abstract: The invention discloses a stratification developing method for a complex fault block thin oil reservoir. The method comprises the steps that the structure of the oil reservoir to be developed and the magnitude of edge-bottom water oil reservoir energy are determined; on the basis of determining the structure, fine geological stratification is achieved, and development units are detailed to single sand bodies; on the basis of fine geological stratification, the reservoir properties of all the single sand bodies are evaluated, and the spacing layer distribution conditions and physical characteristics of all the single sand bodies are determined; on the basis of determining reservoir evaluation, the residual oil distribution law and residual recoverable reserves of all the single sand bodies are determined through development effect analysis; after the residual oil distribution law is determined, series of strata recombination boundaries of horizontal well deployment target layers and vertical well drilling reservoir are obtained by utilizing numerical simulation in combination with field experience; on the basis of determining the conditions, according to the stratification developing technology, well pattern overall planning and deployment are carried out, and the stratification developing scheme is complied. According to the stratification developing method, the usage degree of the oil reservoir reserves can be increased, the development effect of the oil reservoir can be improved, and the recovery efficiency of the oil reservoir is enhanced.

Measuring method and system for reservoir pore structure of compact oil and gas reservoir

Abstract: The invention provides a measuring method for reservoir pore structure of compact oil and gas reservoir. The measuring method comprises steps: core characteristics of a compact oil and gas reservoir sample are obtained; the scattering length density of the compact oil and gas reservoir sample is calculated through the core characteristics of the sample; the scattering intensity of the sample is calculated through scattering length density; the pore superficial area of the sample is calculated through the scattering intensity; the total pore volume of the sample is calculated through the pore superficial area. The reservoir pore structure of the compact oil and gas reservoir is measured through SANS/USANS, The trends of the result and the pore size distribution curves of the N2 adsorption experiment are consistent. Low pressure adsorption experiments show that the content of micropores is low, and show existence of micron-size pores, and the pores are not communicated. The measuring precision is high, and the measuring accuracy is high.

Petrophysical rock classification in the Cotton Valley tight-gas sandstone reservoir with a clustering pore-system orthogonality matrix

Abstract: Petrophysical rock classification is an important component of the interpretation of core data and well logs acquired in complex reservoirs. Tight-gas sandstones exhibit large variability in all petrophysical properties due to complex pore topology resulting from diagenesis. Conventional methods that rely dominantly on hydraulic radius to classify and rank reservoir rocks are prone to rock misclassification at the low-porosity and lowpermeability end of the spectrum. We introduce a bimodal Gaussian density function to quantify complex pore systems in terms of pore volume, major pore-throat radii, and pore-throat radius uniformity. We define petrophysical dissimilarity (referred to as orthogonality) between two different pore systems by invoking the classic “bundle of capillary tubes” model and subsequently classify rocks by clustering an orthogonality matrix constructed with all available mercury injection capillary pressure data. The new method combines several rock textural attributes including porosity, pore-throat radius, and tortuosity for ranking reservoir rock quality in terms of flow capacity. We verify the new rock classification method with field data acquired in the Cotton Valley tight-gas sandstone reservoir located in the East Texas basin. The field case shows that the new method consistently identifies and ranks rock classes in various petrophysical data domains, including porositypermeability trends, pore-size distribution, mercury injection capillary pressure, and NMR transverse relaxation time (T2) spectra. Relative permeability curves, which are difficult to measure in the laboratory for tight rocks, are quantified with Corey-Burdine’s model using the bimodal Gaussian pore-size distribution and are validated with core data.

Exploration method of faulted basin slope oil reservoir distribution

Abstract: The invention relates to an exploration method of faulted basin slope oil reservoir distribution and belongs to the field of oil exploration technology. In allusion to the later period of faulted basin exploration, through statistics of related information of source rock, fluid potential, sedimentary rock phase and fault in a target area and according to the principle of source potential conduction, the above information is comprehensively analyzed so as to determine a favorable oil reservoir distribution area in the target area. Forward oil control exploration limitations are broken and are shifted to negative structure and positive structure. Comprehensive analysis is carried out according to an oil source, fluid potential, sedimentary facies distribution and fault occurrence in the area, the slope is evaluated, and a favorable exploration target area is selected.

Evaluation of Coalbed Methane Reservoirs

Abstract: Coal, unlike conventional gas reservoirs, is both the reservoir rock and the source rock for methane. While much of the gas generated during coalification migrated out of the coal seam, significant quantities remain in coal that can be produced from a seam by understanding and evaluating the unique properties of coal. The CBM characteristics and testing techniques to determine key reservoir parameters needed for developing a CBM prospect will be discussed in the following sections.

Reservoir rock typing of Upper Shu’aiba limestones, northwestern Oman

Abstract: Core samples from seven wells in Lower Cretaceous limestones of the Upper Shu’aiba Member were characterized by conventional core analyses, petrography, bulk chemistry and mercury-injection capillary pressure data to define reservoir rock types (RRT). In the main oilfield studied, lithofacies are arranged in three main belts corresponding to ramp crest, upper slope and lower slope, with bioclast content and size decreasing down depositional dip. Rock typing is based on the observation of distinct, but overlapping, porosity–permeability transforms for each lithofacies, although most samples plot in or below the class 3 field of Lucia, reflecting the presence of abundant lime-mud matrix. Because of the wide range of porosity in each of the main lithofacies, an arbitrary division at 20% porosity is used in combination with lithofacies to define RRT with both three-dimensional (3D) geological significance and distinct ranges of permeability and capillary pressure characteristics. The use of total porosity as a rock-typing criterion is based on the interpretation that porosity is controlled on the reservoir scale by the depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms a have low clay, and, thus, highest porosity. Because both lithofacies and porosity are linked to the sedimentological and stratigraphic organization of the Upper Shu’aiba clinoforms, the RRT can potentially be implemented in a reservoir model for assigning distinct ranges of petrophysical properties to the different architectural elements comprising each clinoform. Two additional grain-dominated RRT have also been defined in a single core that was available from a second oilfield.

Geophysical characterization and petrographic analysis of cap and reservoir rocks within the Lund Sandstone in Kyrkheddinge

Abstract: Geophysical investigations in the Kyrkheddinge area including seismic surveys and wire-line logging were carried out by Swedegas AB between 1978-1985. This study has used the data to make a geophysical and petrographic characterization of cap-rock and reservoir sections within the Lund Sandstone in Kyrkheddinge to evaluate the conditions for storing gas in the bedrock. The Lund Sandstone comprises deposits of Campanian and Santonian age. Four lithologies have been identified; quartzose sandstone, calcareous sandstone, arenaceous limestone, and argillaceous limestone. Log correlation between four wells shows a dome-shaped trap structure beneath the surface at approximately 600 m depth and a lateral continuity of several cap-rock and reservoir units. Petrophysical properties show heterogeneous reservoir sandstone units with excellent porosity and permeability values as well as impermeable heterogeneous cap-rock units with varying clay content. The Lund Sandstone displays in general suitable properties for storing gas. However, seismic data revealed the existence of a possible fault that may have affected the closed structure of the B reservoir, which led to abandoning the project beside strategic decision on optimal placing and storage type. Further studies on how the fault affects the storage possibilities is recommended. Moreover, investigations have identified potential sand intervals with overlying cap-rocks at greater depths than the sand B reservoir which could be studied in more detail. There is a great potential to use the vast amount of data and knowledge from the site investigations at Kyrkheddinge for cap-rock and reservoir modeling, and research regarding storage of natural gas and CO2.