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Texas
History Matching Time-Lapse Surface-Gravity and Well-Pressure Data With Ensemble Smoother for Estimating Gas Field Aquifer Support—A 3D Numerical Study
Glegola, M.. (Delft University of Technology) | Ditmar, P.. (Delft University of Technology) | Hanea, R.G.. G. (TNO and Delft University of Technology) | Eiken, O.. (Statoil) | Vossepoel, F.C.. C. (Shell International Exploration and Production B.V.,the Netherlands) | Arts, R.. (TNO) | Klees, R.. (Delft University of Technology)
Summary Water influx is an important factor influencing production of gas reservoirs with an active aquifer. However, aquifer properties such as size, porosity, and permeability are typically uncertain and make predictions of field performance challenging. The observed pressure decline is inherently nonunique with respect to water influx, and large uncertainties in the actual reservoir state are common. Time-lapse (4D) gravimetry, which is a direct measure of a subsurface mass redistribution, has the potential to provide valuable information in this context. Recent improvements in instrumentation and data-acquisition and -processing procedures have made time-lapse gravimetry a mature monitoring technique, both for land and offshore applications. However, despite an increasing number of gas fields in which gravimetric monitoring has been applied, little has been published on the added value of gravity data in a broader context of modern reservoir management on the basis of the closed-loop concept. The way in which gravity data can contribute to improved reservoir characterization, production-forecast accuracy, and hydrocarbon-reserves estimation is still to be addressed in many respects. In this paper, we investigate the added value of gravimetric observations for gas-field-production monitoring and aquifer-support estimation. We perform a numerical study with a realistic 3D gas field model that contains a large and complex aquifer system. The aquifer support and other reservoir parameters (i.e., porosity, permeability, reservoir top and bottom horizons) are estimated simultaneously using the ensemble smoother (ES). We consider three cases in which gravity only is assimilated, pressure only is assimilated, and gravity and pressure data are assimilated jointly. We show that a combined estimation of the aquifer support with the permeability field, porosity field, and reservoir structure is a very challenging and nonunique history-matching problem, in which gravity certainly has an added value. Pressure data alone may not discriminate between different reservoir scenarios. Combining pressure and gravity data may help to reduce the nonuniqueness problem and provide not only an improved gas- and water-production forecast and gas-in-place evaluation, but also a more-accurate reservoir-state description.
- North America > United States (1.00)
- Europe > Netherlands (0.69)
- Asia > Middle East (0.67)
- Europe > Norway > North Sea (0.46)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/11 > Åsgard Field > Midgard Field > Ile Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/11 > Åsgard Field > Midgard Field > Garn Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/2 > Åsgard Field > Midgard Field > Ile Formation (0.99)
- (22 more...)
Summary On the basis of micro- and mesoscale investigations, a new mathematical formulation is introduced in detail to investigate multiscale gas-transport phenomena in organic-rich-shale core samples. The formulation includes dual-porosity continua, where shale permeability is associated with inorganic matrix with relatively large irregularly shaped pores and fractures, whereas molecular phenomena (diffusive transport and nonlinear sorption) are associated with the kerogen pores. Kerogen is considered a nanoporous organic material finely dispersed within the inorganic matrix. The formulation is used to model and history match gas-permeation measurements in the laboratory using shale core plugs under confining stress. The results indicate significance of molecular transport and strong transient effects caused by gas/solid interactions within the kerogen. In the second part of the paper, we present a novel multiscale perturbation approach to quantify the overall impact of local porosity fluctuations associated with a spatially nonuniform kerogen distribution on the adsorption and transport in shale gas reservoirs. Adopting weak-noise and mean-field approximation, the approach applies a stochastic upscaling technique to the mathematical formulation developed in the first part for the laboratory. It allows us to investigate local kerogen-heterogeneity effects in spectral (Fourier-Laplace) domain and to obtain an upscaled "macroscopic" model, which consists of the local heterogeneity effects in the real time—space domain. The new upscaled formulation is compared numerically with the previous homogeneous case using finite-difference approximations to initial/boundary value problems simulating the matrix gas release. We show that macrotransport and macrokinetics effects of kerogen heterogeneity are nontrivial and affect cumulative gas recovery. The work is important and timely for development of new-generation shale-gas reservoir-flow simulators, and it can be used in the laboratory for organic-rich gas-shale characterization.
Summary The Dykstra-Parsons method (Dykstra and Parsons 1950) is used to predict the performance of waterflooding in noncommunicating stratified reservoirs. Much interest has been shown recently in the application of the method to chemical flooding, particularly for the case of polymer injection used for mobility control. The original method assumes that the reservoir layers are horizontal; however, most oil reservoirs exhibit a dip angle, with water being injected in the updip direction. Therefore, it is important to account for the effect of inclination on the performance of the method. A modification of the Dykstra-Parsons equations is obtained to account for reservoir inclination. The developed model includes a dimensionless gravity number that accounts for the effect of the dip angle and the density difference between the displacing and displaced fluids. The derived equation that governs the relative locations of the displacement fronts in different layers is nonlinear, includes a logarithmic term, and requires an iterative numerical solution. This solution is used to estimate the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio at the time of water breakthrough in successive layers. Solutions for stratified systems with log-normal permeability distribution were obtained and compared with horizontal systems. The effects of the gravity number, the mobility ratio, and the Dykstra-Parsons permeability-variation coefficient (VDP) on the performance were investigated. Cases of updip and downdip injection are discussed. It was found that for a positive gravity number (updip water injection), performance is enhanced in terms of delayed water breakthrough, increased fractional oil recovery, and decreased water cut as compared with horizontal layers. This occurs for both favorable and unfavorable mobility ratios but is more evident in unfavorable mobility ratios and more-heterogeneous cases. For the case of a negative gravity number (downdip water injection or updip gas injection), the opposite behavior was observed. The results were also compared with the performance of inclined communicating reservoirs with complete crossflow. The effect of communication between layers was found to improve fractional oil recovery for favorable and unit mobility ratios and decrease recovery for unfavorable mobility ratio.
- Asia (1.00)
- North America > United States > Texas (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Summary Simple methods, such as the use of density during compositional simulations, often fail to identify the phases correctly, and this can cause discontinuities in the computed relative permeability values. The results are then physically incorrect. Furthermore, numerical simulators often slow down or even stop because of discontinuities. There are many important applications in which the phase behavior can be single phase, gas/liquid, liquid/liquid, gas/ liquid/liquid, or gas/liquid/solid at different times in different gridblocks. Assigning physically correct phase identities during a compositional simulation turns out to be a difficult problem that has resisted a general solution for decades. We know that the intensive thermodynamic properties, such as molar Gibbs free energy, must be continuous, assuming local equilibrium, but this condition is difficult to impose in numerical simulators because of the discrete nature of the calculations. An alternative approach is to develop a relative permeability model that is continuous and independent of the phase numbers assigned by the flash calculation. Relative permeability is a function of saturation, but also composition, because composition affects the phase distribution in the pores (i.e., the wettability). The equilibrium distribution of fluids in pores corresponds to the minimum in the Gibbs free energy for the entire fluid/rock system, including interfaces. In general, however, this relationship is difficult to model from first principles. What we can easily do is calculate the molar Gibbs free energy (G) of each phase at reference compositions where the relative permeabilities are known or assumed to be known and then interpolate between these values by use of the G calculated during each timestep of the simulation. Relative permeability values calculated this way are unconditionally continuous for all possible phase-behavior changes, including even critical points. We tested the new relative permeability model on a variety of extremely difficult simulation problems with up to four phases, and it has not failed yet. We illustrate several of these applications.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.30)
Introduction Arctic oil and gas have been E&P targets for several decades. However, the petroleum potential of this region is far from being fully understood. Assessments of undiscovered petroleum of the Arctic indicates that it holds asignificant amount of the world's undiscovered gas and oil (Gautier et al.,2009) and recent assessments also indicate the potential of shale resourceplays for oil and gas, for example on the Alaska North Slope (Houseknecht,2012). In this paper we will present workflows for efficient petroleumexploration risk and resource assessments for both conventional andunconventional resources in the Arctic, and we will also present a recentsuccessful exploration campaign which resulted in the first technically provenshale oil play on the Alaska North Slope. This will demonstrate the value of applying the same approach to otherArctic petroleum provinces, resulting in a) increased understanding of existingand hypothetical petroleum systems, b) more accurate assessments of theremaining potential hydrocarbon resources on a regional scale, c) more accuratescreening of exploration opportunities and assessments of exploration risk, andd) provide an efficient, geology based and auditable approach to petroleumexploration risk and resource assessments. Petroleum Systems Modeling Using all of the available G&G data to create multi-dimensionalpetroleum systems models is the only technology that can integrate andprocess all of the available geologic data in order to enable a completeassessment of the potential value of the hydrocarbon resources. The reason isthat it adds the results of a geologic process based analysis to the existingG&G data to provide critical additional information. For example, it is theonly method that enables hydrocarbon properties and oil vs. gas distributionsto be understood and predicted, which is a critical issue for thedifferentiation of shale resource plays into oil and gas prone targets. Petroleum systems modeling enables the dynamics of sedimentary basins andtheir associated fluids to be evaluated to see if past conditions were suitablefor generation of hydrocarbons to fill potential reservoirs and to bepreserved. Applications include predictions of the extent and timing ofpetroleum generation from source rocks, reconstructions of basin architecture, migration pathways, locations of potential traps and accumulations, andanalysis of risk based on various geologic, geochemical, or fluid-flowassumptions (Magoon and Dow, 1994; Peters et al., 2009). The technology usesdeterministic computations to forward simulate (i.e. from the geologic past tothe present) the thermal history of a basin and the associated generation, migration, and accumulation of petroleum (Hantschel and Kauerauf, 2009; Peters,2009). These results are then combined with statistical assessments to enableimproved assessments of the petroleum resources, therefore enabling the entiresequence of analyses from petroleum exploration risk to resource assessments tobe supported.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.50)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (6 more...)
Structure and Hydrocarbon Prospects of the Russian Western Arctic Shelf
Stoupakova, A.V. (Moscow State University) | Kirykhina, T.A. (Moscow State University) | Suslova, A.A. (Moscow State University) | Kirykhina, N.M. (Moscow State University) | Sautkin, R.S. (Moscow State University) | Bordunov, S.I. (Moscow State University)
Abstract The Russian Western Arctic Basins cover the huge area including the Barentsand Kara seas, the western part of the Laptev sea and adjacent territories withsome archipelagoes and islands (Spitsbergen, Franz Josef Land, SevernayaZemlya, Novaya Zemlya, etc.). They comprise the Barents and Kara Basins, thenorthern areas of the Timan-Pechora Basin, the North West Siberia, includingYamal and Gidan peninsulas and the Yenisey-Khatanga Basin. Within the RussianWestern Arctic basins the following main tectonic elements can be identified:extensional depressions (Central-Barents, Yenisei-Khatanga, West Siberia, EastUrals) with sedimentary thickness is more than 12–14 km; platform massiveswith average thickness of sediments of 4 – 6 km, monoclines and tectonic steps, like transition zones between extensional depressions and platform massives. Western Arctic basins are filled by mainly Palaeozoic and Mesozoic sedimentarysuccessions. In the sedimentary cover of this large region, many commonstratigraphic complexes and unconformities can be traced within Palaeozoic andMesozoic complexes that show similarity of geological conditions of theirformation. Analysis of the Russian Western Arctic basins, their structures andhydrocarbon prosepctivity shows the areas, which are favourable for hydrocarbonaccumulations. Deep depressions, as areas of long-term and stable sinking, arehighly promising zones for the accumulation of predominantly gas fields. Theyform regional gas accumulation belts, extending for thousands of kilometres, where the largest fields can be expected in the zones of their intersectionwith the major tectonic elements of another strike. Within the Barents-Karashelf, the large belt of predominantly gas accumulation extends from the northof the West Siberian province through the South Kara basin and into the BarentsSea. The second potential belt of predominantly gas accumulation may beassociated with the North Barents ultra-deep depression. On the flanks of thedepressions the sedimentary cover profile does not contain the complete set ofoil-and-gas-bearing complexes, identified in the central parts of theextensional depressions. The reservoirs can be filled by HC due to the lateralmigration of fluids from the neighbouring kitchens or from their own dominantoil-and-gas source rock strata. For the formation of oil accumulations, themost favourable are platform massifs and ancient uplifts areas.
- North America (1.00)
- Europe > Russia > Barents Sea (1.00)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug (1.00)
- (3 more...)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- Phanerozoic > Mesozoic > Triassic (0.70)
- Phanerozoic > Paleozoic > Devonian > Upper Devonian (0.69)
- (2 more...)
- Geology > Sedimentary Basin (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- (3 more...)
- Europe > Russia > Northwestern Federal District > Northwestern Federal District > Nenets Autonomous Okrug > Timan-Pechora Basin (0.99)
- Europe > Russia > Northwestern Federal District > Nenets Autonomous Okrug > Timan-Pechora Basin > Khoreiver Basin > Pomorskoye Field (0.99)
- Europe > Russia > Northwestern Federal District > Komi Republic > Nenets Autonomous Okrug > Timan-Pechora Basin (0.99)
- (46 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (0.94)
Copyright 2012, Offshore Technology Conference This paper was prepared for presentation at the Arctic Technology Conference held in Houston, Texas, USA, 3-5 December 2012. This paper was selected for presentation by an ATC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract This paper characterizes the spatial and temporal variability of river overflooding on the sea ice and related pipeline and facility siting concerns for the nearshore region of the Alaskan Beaufort Sea. This phenomenon occurs each spring during a brief period when river discharge precedes the break-up of the landfast sea ice.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > East Texas Salt Basin > Colville Field (0.89)
- North America > United States > Alaska > North Slope Basin > Western North Slope > Colville River Field > Kingak Formation (0.89)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay > East Irish Sea Basin > Liverpool Bay > Block 110/7c > Rivers Field > Rivers Field > Rivers Field > Rivers Field > Darwen Field (0.89)
- (23 more...)
Introduction of Nippleless Tubing Stop Plug Application in Pakistan
Sherwani, Waseem Akhtar (1 Eastern Testing Service (Pvt) Limited) | Qureshi, Imran (1 Eastern Testing Service (Pvt) Limited) | Khattak, Kifayatullah (1 Eastern Testing Service (Pvt) Limited) | Ali, Abdul Salam (1 Eastern Testing Service (Pvt) Limited) | Ali, Syed Dost (2 Pakistan Petroleum Limited)
Abstract Well control is the management of the hazardous effects caused by the unexpected well release. In a production well, downhole safety valve and X-mass tree are considered the main barriers against the well release in the event of a worst case scenario surface disaster. Inadequate risk management and improperly managed well control situations cause blowouts, potentially resulting in a fire hazard. This paper describes a case history of a production well where a tubing string was roded severely during production phase. The problem was detected while attempting to retrieve the separation sleeve in the long string which was not accessible at the required depth. Downhole camera indicated that 90% of the long string had been eroded and remaining 10% is connected with the flow coupling. Thus, full workover job was required to replace tubing strings. However, the lack of well control barrier in the tubing to prevent uncontrolled flow of hydrocarbons prior to blowout preventer (BOP) installation for the workover was a serious safety concern. Introduction of Nippleless Tubing-Stop Plug technology provide an effective, safe and economical remedial solution to the problem.
- Asia > Pakistan (0.88)
- North America > United States > Texas (0.29)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
ABSTRACT Relative permeability to formation fluids is an essential input into reservoir characterization, dynamic modeling, and production prediction. In this work, a method combining evaporation and unsteady-state pressure-falloff technique is developed to measure gas-phase relative permeability on tight-gas cores for both drainage and imbibition cycles. Toluene is used to mimic formation water and its saturation is varied by evaporation and determined by mass balance. Nitrogen gas is used to imitate the hydrocarbon fluid, and the gas effective permeability at certain toluene saturations is measured by the pressure-falloff technique. The method greatly reduces the measurement duration, and provides a relatively simple and effective way to characterize the gas-phase relative permeability for tight-gas cores. It has been applied on ~30 tight-gas cores from various fields. Results show that the gas relative permeabilities follow the Corey model with a Corey exponent of ~2 for the drainage cycle and ~3 for the imbibition cycle. The assumptions are studied by both numerical modeling and separate experiments.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.57)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- North America > United States > Colorado > Uinta Basin (0.99)
- (7 more...)
Technology Focus The oil and gas business continues to migrate toward deeper plays, less drillable geology, and more tortuous directional objectives, all within a cost framework that sustained high oil prices are driving upward. Our part of the oil and gas industry—well construction—is having to expand drilling capability and continuously improve efficiency so that operators can keep marginal projects economic and avoid dramatic departures from planned schedule and cost. Against this background, it is vital that our knowledge of the downhole drilling environment improves. The historical habit of “try it and see,” driven by an absence of downhole measurements or the applied use of them, all too frequently failed to deliver predictable performance, especially in technically demanding scenarios. Our industry deserves better than that, so it is appropriate to ask, “Are we optimized yet?” As in previous features, there is progress to celebrate. The articles here will demonstrate that the quest to improve understanding of drillstring and tool behavior, to optimize well placement, and to execute with failure avoidance and ever-improving performance continues. It is much rarer now to see operations plagued by poor bit selection, baffled drilling teams, and repeated tool failures—a tribute to the drilling industry’s hunger to improve. There is, however, more to do—rate of penetration to be raised, bit life to be lengthened, tool life to be improved, geosteering to be refined. So, if your team is not actively working on improvement in these areas or is not equipped with the knowledge or data to do so, ask why; there are people and tools out there ready to help. Let’s remember that, when we integrate the measurements, the gurus, and the operational practitioners, improvement usually results. The key to an optimized operation is knowledge; and performance will tell you whether your operation has enough of it. So, if predictable, improving performance is not what you see from your operation or your service, keep pushing. Our industry needs it. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 151175 A Systematic Approach To Improving Directional Drilling Tool Reliability in HP/HT Horizontals in the Haynesville Shale by Errol Pinto, Shell Upstream Americas, et al. SPE 151377 Anomalous Behaviors of a Propagating Borehole by Luc Perneder, University of Minnesota, et al.
- North America > United States > Texas (0.26)
- North America > United States > Minnesota (0.26)
- North America > United States > Louisiana (0.26)
- North America > United States > Arkansas (0.26)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drill Bits (1.00)
- Well Drilling > Drilling Equipment (0.92)
- Well Drilling > Drillstring Design > BHA design (0.40)