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Jonny Hesthammer - One of the best experts on this subject based on the ideXlab platform.

  • The Statfjord Field, Blocks 33/9, 33/12 Norwegian sector, Blocks 211/24, 211/25 UK sector, Northern North Sea
    Geological Society London Memoirs, 2003
    Co-Authors: Kathryn A. Gibbons, Charles A. Jourdan, Jonny Hesthammer
    Abstract:

    Abstract The Statfjord Field, the largest oil field in the Northern North Sea, straddles the Norway/UK boundary and is located on the southwestern part of the Tampen Spur within the East Shetland Basin. The accumulation is trapped in a 6-8° W-NW dipping rotated fault block comprised of Jurassic-Triassic strata sealed by Middle to Upper Jurassic and Cretaceous shales Reserves are located in three separate reservoirs: Middle Jurassic deltaic sediments of the Brent Group, Lower Jurassic marine-shelf sandstones and siltstones of the Dunlin Group; and Upper Triassic-lowermost Jurassic fluviatile sediments of the Statfjord Formation. The majority of reserves are contained within the Brent Group; and Statfjord Formation sediments which exhibit good to excellent reservoir properties with porosities ranging from 20-30% permeabilities ranging up to several darcies, and an average net-to-gross of 60-75%. The sandstones and siltstones of the Dunlin Group have poorer reservoir properties where the best reservoir unit exhibits an average porosity of 22%, an average permeability 300 raD and net-to-gross of 45% Structurally, the field is subdivided into a main field area characterized by relatively undeformed W-NW dipping strata, and a heavily deformed east flank area characterized by several phases of 9eastward9 gravitational collapse Production from the field commenced in 1979 and as of January 2000, 176 wells have been drilled. The oil is undersaturated and no natural Gas-cap is present. The drainage strategy has been to develop the Brent and Dunlin Group reservoir with pressure maintenance using water injection and the Statfjord Formation reservoir by Miscible Gas Flood. However, a strategy to improve recovery by implementing water alternating Gas (WAG) methods is gradually being implemented for both the Brent and Statfjord reservoirs. Current estimates indicate that by 2015 a total of 666 x 10 6 Sm 3 (4192 MMBBL) of oil will be recovered and 75 GSm 3 (2.66 TCF) Gas will be exported from the field

Eva K. Halland - One of the best experts on this subject based on the ideXlab platform.

  • Sedimentology and Shale Modeling of a Sandstone-Rich Fluvial Reservoir: Upper Statfjord Formation, Statfjord Field, Northern North Sea
    AAPG Bulletin, 1993
    Co-Authors: Alister C. Macdonald, Eva K. Halland
    Abstract:

    Sandstone-rich fluvial reservoirs of the upper part of the Statfjord Formation in Statfjord field, northern North Sea, include significant proportions of interstratified shale beds which complicate the production of oil under a high-pressure Miscible Gas Flood. Flood-plain mudstones, characterized by pedogenic alteration, and finely laminated abandoned channel facies form the most important flow barriers. Mudstones deposited in Flood plains are expected to have a greater lateral continuity than those deposited in abandoned channels. Fluctuations in allogenic factors such as base level and sediment-supply rates have led to a variable preservation of the mudstones. This combination of different facies types and fluctuating allogenic control has led to a complex barrier dist ibution within the reservoir which is difficult to describe using conventional mapping techniques. A procedure, based on two stochastic simulation techniques, has been adopted in order to model the complex barrier distribution. A two-dimensional Markov field model is used as an alternative to conventional shale mapping to describe the distribution of shale beds that are correlated between two or more wells. The model is based on probabilistic estimations of shale continuity between well pairs and allows the simulation of local channel incision through otherwise extensive shale beds. A marked-point process model is adopted to describe the distribution of smaller scale discontinuous barriers within the reservoir sand bodies. It is based on probabilistic estimations of shale dimensions defined using cumulative frequency distributions. The stochastic modeling procedure allows greater flexibility to include a variety of geological interpretations and assumptions in the heterogeneity model, and the increased geological input results in more realistic models of communication between and vertical permeability within the reservoir sand bodies.

T.l.m. Van Der Heijden - One of the best experts on this subject based on the ideXlab platform.

  • Modeling of Miscible CO2 foam displacements with oil
    2009
    Co-Authors: T.l.m. Van Der Heijden
    Abstract:

    Fractional-flow theory provides key insights into complex foam IOR displacements and acts as a benchmark for foam simulators. In some cases with mobile oil present the process can be represented as a two-phase displacement. We examine two such cases. A first-contact Miscible Gas Flood with foam injection includes a chemical shock defining the surfactant front and a Miscible shock defining the Gas front. The optimal water fraction for the foam (i.e., the water fraction that gives the fastest oil recovery) maintains the Gas front slightly ahead of the foam (surfactant) front. A first-contact Miscible foam process with surfactant dissolved in the (supercritical) CO2 is influenced by surfactant adsorption on rock and also on partitioning of the surfactant between water and CO2. A foam with surfactant that is more soluble in the water would propagate slowly, regardless of the surfactants absolute solubility or the level of adsorption on rock. This study forms part of a larger study combining fractional-flow modeling of these processes with computer simulation. The simulations verify the results obtained with fractional-flow methods and illustrate the challenges of accurate simulation of these processes. For both cases (i.e., first-contact Miscible Gas Flood with foam injection, and first-contact Miscible foam process with surfactant dissolved in the Gas phase), simulations show that, in the limit of small grid blocks, the solution converges towards the fractional-flow solution. Fractional-flow theory not only predicts the displacement in the absence of dispersion, but helps explain the effects of dispersion on the displacement. Numerical dispersion introduced by the simulator is shown to have significant effects on the outcome of the simulations. At the urfactant front, numerical dispersion can drastically change the nature of the foam front, depending on the foam model used (specifically, the effect of surfactant concentration on foam strength). A foam model where foam is abruptly created at 50% of the injected surfactant concentration mitigates the effects of this dispersion, but the velocity of the foam bank is still altered. Investigation on the influence of adsorption shows that Langmuir-type adsorption models tend to sharpen up the (dispersed) surfactant front and are the least sensitive to dispersion. At the Miscible front, dispersion affects mobilities in the oil and Gas phase; again, fractional-flow theory helps explain the implications for the displacement. In multiple-contact (developed) Miscible displacements, simulations, with dispersion present, show a region of three-phase flow ahead of the Miscible front.

  • Fractional-flow Theory of Foam Displacements with Oil
    11th European Conference on the Mathematics of Oil Recovery, 2008
    Co-Authors: M. Namdar-zanganeh, T.l.m. Van Der Heijden, T. La Force, Seung Ihl Kam, William R. Rossen
    Abstract:

    Fractional-flow theory has proven useful for understanding the factors that control foam displacements and as a benchmark against which to test foam simulators. Most applications of fractional-methods to foam have excluded oil. Recently, Mayberry and Kam (SPE 100964) presented out fractional-flow solutions for foam injection with a constant effect of oil on the foam. We extend fractional-flow methods to foam displacements with oil, using the effects of oil and water saturations on foam as represented in the STARS simulator. There can be abrupt shifts in the composition paths at the limiting water and oil saturations for foam stability. In the imMiscible three-phase SAG displacements examined, if foam collapses at the initial oil saturation in the reservoir, there is a very-small-velocity shock from the injected condition to complete foam collapse. The displacement is nearly as inefficient as if no foam were present at all. It does not matter in these cases whether foam is weakened by low water saturation. The displacement is efficient, however, if foam is unaffected by oil but weakened at low water saturation. These results may reflect our foam model, where foam is only partially destroyed at low water saturations but is completely destroyed by high oil saturation. Two idealized models for three-phase displacements can be represented at two-phase displacements with chemical or Miscible shocks: A model for a first-contact Miscible Gas Flood with foam suggests an optimal water fraction in foam that puts the Gas front just slightly ahead of the foam (surfactant) front. An idealized model of a surfactant Flood with foam for mobility control suggests it is important to inject a sufficiently high water fraction in the foam that the Gas front is behind the surfactant front as the Flood proceeds. We present simulations to verify the solutions obtained with fractional-flow methods.

Curtis D. Sitz - One of the best experts on this subject based on the ideXlab platform.

  • Analysis of a Single-Well Chemical Tracer Test To Measure the Residual Oil Saturation to a Hydrocarbon Miscible Gas Flood at Prudhoe Bay
    SPE Reservoir Evaluation & Engineering, 2000
    Co-Authors: A.p. Cockin, L.t. Malcolm, P.l. Mcguire, R.m. Giordano, Curtis D. Sitz
    Abstract:

    Summary In 1990, a single-well chemical tracer (SWCT) test was performed in Prudhoe Bay to measure the effective waterFlood and Miscible GasFlood residuals over a 12 ft reservoir interval. This is believed to be the first such use of this technology for a hydrocarbon Miscible Gas. This paper describes how the usual SWCT design was modified to accommodate the Miscible Gas, the results of the SWCT, which indicate significantly higher residual oil saturation for Miscible GasFlood than expected from coreFlood experiments, and the subsequent simulation of the test which has provided good agreement with the observed results. The paper shows, with compositional simulation support, that the high apparent residual oil saturation was a consequence of incomplete volumetric sweep by the Miscible Gas and draws on the experiences of this test to make recommendations for the design of future SWCT tests measuring residuals to GasFlooding. Introduction The Prudhoe Bay Miscible Gas Project (PBMGP) is the world's largest Miscible Flood. Prior to startup in 1987, numerous slim tube, coreFlood, and phase behavior experiments were carried out to confirm the recovery potential of the process. Since the startup of the PBMGP a fibreglass observation well has been used to observe the Flood progress and a sidetrack cored to observe the extent of the Gas sweep. In 1990, a single-well chemical tracer (SWCT) test was carried out on a producing well which first measured the effective residual to waterFlood and then to Miscible GasFlood. The attraction of the SWCT was that it investigated a much larger volume of rock than a coreFlood and native wettability, away from the wellbore, should be assured. However, it should be recognized that this still only represents a small sample which may not represent the average performance on a broader scale. The tests were successfully carried out although production problems resulted in four tests, instead of the originally planned two, finally being performed. The subsequent analysis suggested an effective residual oil saturation to the Miscible Flood (Sorm) of 8%±2%. This was somewhat higher than the coreFlood observed values of around 2%. Compositional simulation work has since been carried out to model the full suite of tests, including the aborted ones, to ascertain whether this higher value really conflicted with the coreFlood results. Throughout the paper the remaining oil saturation following a water- or GasFlood is referred to as the effective residual oil saturation since the paper demonstrates that the apparent high residual oil saturation after a Miscible GasFlood was a consequence of incomplete volumetric sweep. Hence, the measured remaining, or effective, residual saturation could have been lowered further if complete sweep had occurred. The theory behind a SWCT test is described in detail in Ref. 1 and recovery methods in Ref. 2. Background The Prudhoe Bay oil field on the north coast of Alaska is the largest oil field in the USA. The major producing sand is the Sadlerochit, which can be over 400-ft thick in some locations. It is mostly comprised of high-permeability fluvial sands with interbedded shales. Some of these shales are continuous over large areas while the majority are discontinuous over interwell distances. The structural and hydrocarbon histories are documented in Ref. 3, while Ref. 4 covers the reservoir description. Prudhoe Bay is overlain by a large Gas cap. All produced Gas components not used for fuel or spiked into the export oil line are reinjected either as a lean Gas back into the Gas cap or as a rich Gas into the PBMGP or other projects. Lean Gas injection into the Gas cap recovers additional relict oil by vaporization. The expansion of the Gas cap downwards recovers oil by gravity drainage. Around the periphery of the field there are approximately 200 inverted nine-spot patterns undergoing waterFlood or water-alternating Miscible GasFlood. The general history of the development of Prudhoe Bay is described in more detail in Ref. 5. The PBMGP was preceded by a pilot at Drill Site 13 in 1982 prior to the startup of the central Gas facility (CGF) in 1987. The CGF has since been expanded several times and now produces up to 550 mmscf/d of Miscible Gas. To date, 1.6 trillion scf of Miscible Gas have been injected. The development of the PBMGP is documented by Refs. 6 and 7. The optimization of the Flood is achieved by directing the Miscible Gas to the most efficient patterns, as described in Ref. 8, and the use of predictive tools described in Refs. 9 and 10. During 1993, the need to sidetrack Injector DS 13-18 provided an opportunity to acquire additional information on the vertical sweep of the injected Gas and the extent to which the Miscible Gas was reducing the oil saturations in this immature pattern (see Ref. 11). Prior to the start of the PBMGP, continuous and water-alternating Miscible Gas (WAG) Floods were carried out on 16 plugs taken from a total of 4 preserved cores. These cores were injected with different Miscible Gas compositions and varying quantities of between 0.88 and 3.74 stock tank pore volumes. They exhibited residual to Miscible Gas saturation values between 1.0% and 4.5% (see Ref. 12), with an average of S orm. In 1990, the magnitude of the reserves being booked to the PBMGP warranted the investment in a SWCT test to provide additional confidence that Miscible Flooding in the field could achieve the low residuals suggested by the preserved state coreFloods.

  • Design, Implementation and Simulation Analysis of a Single-Well Chemical Tracer Test To Measure the Residual Oil Saturation to a Hydrocarbon Miscible Gas at Prudhoe Bay
    Software - Practice and Experience, 1998
    Co-Authors: A.p. Cockin, L.t. Malcolm, P.l. Mcguire, R.m. Giordano, Curtis D. Sitz
    Abstract:

    In 1990 a single well chemical tracer (SWCT) test was performed in Prudhoe Bay to measure the effective water Flood and Miscible Gas Flood residuals over a 12 ft reservoir interval. This is believed to be the first such use of this technology for a hydrocarbon Miscible Gas. This paper describes how the usual SWCT design was modified to accommodate the Miscible Gas, the results of the SWCT, which for the Miscible Gas part were significantly higher than Miscible Gas coreFlood residuals, and the subsequent simulation of the test which has provided good agreement with the observed results. The paper explains, with simulation support, what caused the measured residuals to be higher than expected, and draws on the experiences of this test to make recommendations for the design of future SWCT tests measuring residuals to Gas Flooding.

Kathryn A. Gibbons - One of the best experts on this subject based on the ideXlab platform.

  • The Statfjord Field, Blocks 33/9, 33/12 Norwegian sector, Blocks 211/24, 211/25 UK sector, Northern North Sea
    Geological Society London Memoirs, 2003
    Co-Authors: Kathryn A. Gibbons, Charles A. Jourdan, Jonny Hesthammer
    Abstract:

    Abstract The Statfjord Field, the largest oil field in the Northern North Sea, straddles the Norway/UK boundary and is located on the southwestern part of the Tampen Spur within the East Shetland Basin. The accumulation is trapped in a 6-8° W-NW dipping rotated fault block comprised of Jurassic-Triassic strata sealed by Middle to Upper Jurassic and Cretaceous shales Reserves are located in three separate reservoirs: Middle Jurassic deltaic sediments of the Brent Group, Lower Jurassic marine-shelf sandstones and siltstones of the Dunlin Group; and Upper Triassic-lowermost Jurassic fluviatile sediments of the Statfjord Formation. The majority of reserves are contained within the Brent Group; and Statfjord Formation sediments which exhibit good to excellent reservoir properties with porosities ranging from 20-30% permeabilities ranging up to several darcies, and an average net-to-gross of 60-75%. The sandstones and siltstones of the Dunlin Group have poorer reservoir properties where the best reservoir unit exhibits an average porosity of 22%, an average permeability 300 raD and net-to-gross of 45% Structurally, the field is subdivided into a main field area characterized by relatively undeformed W-NW dipping strata, and a heavily deformed east flank area characterized by several phases of 9eastward9 gravitational collapse Production from the field commenced in 1979 and as of January 2000, 176 wells have been drilled. The oil is undersaturated and no natural Gas-cap is present. The drainage strategy has been to develop the Brent and Dunlin Group reservoir with pressure maintenance using water injection and the Statfjord Formation reservoir by Miscible Gas Flood. However, a strategy to improve recovery by implementing water alternating Gas (WAG) methods is gradually being implemented for both the Brent and Statfjord reservoirs. Current estimates indicate that by 2015 a total of 666 x 10 6 Sm 3 (4192 MMBBL) of oil will be recovered and 75 GSm 3 (2.66 TCF) Gas will be exported from the field