There are large oil and gas resources in the shear zone region of theBeaufort Sea. Development of these resources would entail many factorsfor consideration. One of the most important is the ice load on drillingand production platforms. However, there is very large uncertainty on theice loads in this region due to a clear lack of knowledge of the pack icedriving forces. This pack ice driving force is one of the primarymechanisms that dictate how much force the ice can exert on an offshoreplatform, even if large multi-year ice floes are present. Improvedknowledge of this force would significantly reduce uncertainty in the designice loads, provide essential baseline engineering knowledge and a more reliablestructure, leading to greater regulatory certainty and safer and moreeconomical offshore operations.
The pack ice driving force, as a function of width, can be calculatedthrough an equation in the ISO Arctic Offshore Structures Standard. However, a relevant parameter is still poorly defined for this equationand spans a large range. As a result, calculations of driving forces arevery uncertain, yet it is the key limiting force mechanism for the BeaufortSea. This paper presents the results of a study that investigated meansof refining uncertainty when calculating pack ice driving forces. Anoverview of the standard method of determining these forces is given, as wellas a discussion of the historical development of, and implications ofuncertainty in, calculating the pack ice force. Methods for refining theuncertainty are presented and comparisons are discussed. Numericalmodelling studies offer the greatest potential for refining the uncertaintybased on cost, usefulness, confidence in the results and studyopportunities. The information provided in this paper has applicationsfor refinement of pack ice driving force calculations in current engineeringstandards. A clear understanding of the magnitude of pack ice drivingforces would help to reduce the risk of failure of engineering structures andimprove their safety, by enabling a significantly better definition of theanticipated ice loads and the upper limit of the loads for the BeaufortSea.
Arif, Muhammad (University of Engineering and Technology) | Bhatti, Amanat Ali (University of Engineering and Technology) | Khan, Ahmed Saeed (University of Engineering and Technology) | Haider, Syed Afraz (Kuwait Foreign Petroleum Exploration Company (KUFPEC))
It has long been proved experimentally that the tight gas sands are more pronounced to stress changes as compared to moderate and high permeability reservoirs because of the narrow flow channels of the formation . The consideration of the effect of stress in the evaluation and production performance of tight gas reservoirs is very important in order to make right decisions regarding their development. Due to hydrocarbon production, the effective stress increases causing a reduction in permeability and porosity of the porous medium.
The conventional pressure transient analysis techniques in gas wells based on constant permeability would become unreliable . Consequently, the incorrect evaluation of permeability leads towards wrong decision regarding well stimulation. Also the inflow performance modeling of tight gas reservoirs based on constant permeability will not be corrected as far as evaluation of well's production potential is concerned.
Few studies on tight gas reservoirs considering the effect of stress sensitive permeability used the Raghavan's stress dependent pseudo-pressure approach  for which pressure vs. permeability data was determined experimentally. But, if laboratory data is not available then there is need to develop an analytical approach to generate the pressure vs. permeability data required for the use of stress dependent pseudo-pressure in reservoir evaluation and production performance studies in tight gas reservoirs.
The objective of this paper is to develop an analytical approach, in the absence of lab data, to generate pressure vs. permeability data for the determination of stress dependent pseudo-pressure. This stress dependent pseudo-pressure is used for well test analysis to determine the stress sensitive formation permeability and also to generate production performance in tight gas reservoirs. The developed technique has also been implemented on the field data of a tight gas reservoir to validate the results by using actual well's production history.
Hydrocarbon exploration in the Arctic environment will very much depend onour ability to continuously track ice floes and forecast ice events that maygenerate dangerous loads on exploration and production infrastructure. Wepresent a first-of-its-kind computational framework which is centered aroundnear-real-time satellite imagery and incorporates real-time metocean data,providing automated analysis of such hazards in regions where moving ice ispresent. Our automated framework carries out several ongoing operations: icedetection and classification from satellite images, floe tracking from oneimage to the next, forecasting of floe trajectories beyond the observed tracks,and estimation of an uncertainty cone around the trajectory forecast. Weutilized the IBM InfoSphere™ Streams real-time analytics platform to deploy oursoftware, which made it possible for us to concentrate exclusively onprototyping algorithms, taking for granted the streaming infrastructure neededfor real-time data ingestion and flow between operators. Given our experiencedeveloping this prototype we conclude that a production-worthy, automatedtracking and forecasting capability is computationally feasible and within ourreach.
Crespo, Freddy E. (University of Oklahoma) | Ahmed, Ramadan Mohammed (University of Oklahoma) | Saasen, Arild (Det norske oljeselskap ASA) | Enfis, Majed (University of Oklahoma) | Amani, Mahmood (Texas A&M University at Qatar)
Surge and swab pressures have been known to cause formation fracture, lost circulation, and well-control problems. Accurate prediction of these pressures is crucially important in estimating the maximum tripping speeds to keep the wellbore pressure within specified limits of the pore and fracture pressures. It also plays a major role in running casings, particularly with narrow annular clearances. Existing surge/swab models are based on Bingham plastic (BP) and power-law (PL) fluid rheology models. However, in most cases, these models cannot adequately describe the flow behavior of drilling fluids. This paper presents a new steady-state model that can account for fluid and formation compressibility and pipe elasticity. For the closed-ended pipe, the model is cast into a simplified model to predict pressure surge in a more convenient way. The steady-state laminar-flow equation is solved for narrow slot geometry to approximate the flow in a concentric annulus with inner-pipe axial movement considering yield-PL (YPL) fluid. The YPL rheology model is usually preferred because it provides a better description of the flow behavior of most drilling fluids. The analytical solution yields accurate predictions, though not in convenient forms. Thus, a numerical scheme has been developed to obtain the solutions. After conducting an extensive parametric study, regression techniques were applied primarily to develop a simplified model (i.e., dimensionless correlation). The performance of the correlation has been tested by use of field and laboratory measurements. Comparisons of the model predictions with the measurements showed a satisfactory agreement. In most cases, the model makes better predictions in terms of closeness to the measurements because of the application of a more realistic rheology model. The correlation and model are useful for slimhole, deepwater, and extended-reach drilling applications.
Efficient and robust phase equilibrium computation has become a prerequisite for successful large-scale compositional reservoir simulation. When knowledge of the number of phases is not available, the ideal strategy for phase-split calculation is the use of stability testing. Stability testing not only establishes whether a given state is stable, but also provides good initial guess for phase-split calculation. In this research, we present a general strategy for two- and three-phase split calculations based on reliable stability testing. Our strategy includes the introduction of systematic initialization of stability testing particularly for liquid/liquid and vapor/liquid/liquid equilibria. Powerful features of the strategy are extensively tested by examples including calculation of complicated phase envelopes of hydrocarbon fluids mixed with CO2 in single-, two-, and three-phase regions.
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 kerogenheterogeneity 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.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144774, "History Matching and Production Forecasting With Logs: Effective Completion and Reservoir-Management Tools for Horizontal and Vertical Wells," by Carlos F. Haro, SPE, Occidental Oil & Gas, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. See SPE Res Eval & Eng, October 2012, page 596.
A robust and efficient simulation technique is developed on the basis of the extension of the mimetic finite-difference method (MFDM) to multiscale hierarchical-hexahedral (corner-point) grids by use of the multiscale mixed-finite-element method (MsMFEM). The implementation of the mimetic subgrid-discretization method is compact and generic for a large class of grids and, thereby, is suitable for discretizations of reservoir models with complex geologic architecture. Flow equations are solved on a coarse grid where basis functions with subgrid resolution account accurately for subscale variations from an underlying fine-scale geomodel. The method relies on the construction of approximate velocity spaces that are adaptive to the local properties of the differential operator. A variant of the method for computing velocity basis functions is developed that uses an adaptive local/global (ALG) algorithm to compute multiscale velocity basis functions by capturing the principal characteristics of global flow. Both local and local/global methods generate subgrid-scale velocity fields that reproduce the impact of fine-scale stratigraphic architecture. By using multiscale basis functions to discretize the flow equations on a coarse grid, one can retain the efficiency of an upscaling method, while at the same time produce detailed and conservative velocity fields on the underlying fine grid.
The accuracy and efficacy of the multiscale method is compared with those of fine-scale models and of coarse-scale models with no subgrid treatment for several two-phase-flow scenarios. Numerical experiments involving two-phase incompressible flow and transport phenomena are carried out on high-resolution corner-point grids that represent explicitly example stratigraphic architectures found in real-life shallow-marine and turbidite reservoirs. The multiscale method is several times faster than the direct solution of the fine-scale problem and yields more-accurate solutions than coarse-scale modeling techniques that resort to explicit effective properties. The accuracy of the multiscale simulation method with adaptive local-/global-velocity basis functions is compared with that of the local velocity basis functions. The multiscale simulation results are consistently more accurate when the local/global method is employed for computing the velocity basis functions.
Dew point pressure is a critical measurement for any wet gas reservoir. Condensate blockage is likely when the reservoir pressure decreases below the dew point pressure and this can result in a reduction of gas productivity. Errors in measuring dew point pressure can lead to errors in the estimation of the onset of condensate blockage and thus be detrimental to the management of wet gas fields. This work presents experimental verification of a new method of determining dew point pressures for wet gas fluids. Results obtained from this method are compared to calculated values based on Peng Robinson equation of state.
Dew point pressure determination is important when devising solutions on how to prevent condensate blockage. One possible treatment fluid, carbon dioxide, has the ability to lower dew point pressures and thus delay the onset of condensate blockage. The novel method presented in this work was applied to determine the experimental dew point pressure of several wet gas mixtures as a function of carbon dioxide concentration. These experiments also show the potential of using carbon dioxide to lower dew point pressures in wet gas fields.
Experimental results show close match between the experimental estimates of dew point pressure and the Peng Robinson calculations. Experimental results also support the general observation that carbon dioxide has the ability to lower the dew point pressure of wet gas fields.
The results of this work are useful in Enhanced Oil/Gas Recovery processes that utilize carbon dioxide and for Huff and Puff which uses carbon dioxide to remove and prevent further build-up of condensate banks in wet gas reservoirs. This work investigates experimental conditions showing the change in dew point pressure as a function of carbon dioxide concentration. This dynamic relationship can be used to tune equation of state models which, in turn, allows more accurate reservoir modeling of hydrocarbon recovery process.
Geochemical fingerprinting using gas chromatography techniques is a proven alternative or additional tool to traditional approaches for the production back-allocation such as metering or production logging tools. It can be applied in various scenarios, from commingled reservoirs in a single well to allocation of multiple wells or entire fields produced via the same evacuation system. The approach is fast, cost-effective and does not require interruption of production, thus enabling frequent monitoring of production. The method is based on detailed comparison of fluid compositions obtained from gas chromatography of representative samples acquired from the point of interest (single reservoir, well, etc.), called further the ‘end-member' and the ‘commingled fluid' to be allocated. Production allocation using a geochemical fingerprinting approach has been successfully used across the globe with specific traction in North America, the North Sea region and the Middle East.
Our method is based on analysis of ratios of heights of neighboring chromatographic peaks (compounds) rather than the single peak heights or areas that all the chromatograms have in common. Such approach reduces inconsistencies between light and heavy hydrocarbons due to some problems of reproducibility during the sampling or during the analysis. It also allows us to tackle issues related to the changes in compositions of end-members during production. In addition, the resolution manages the non-linearity of the equations derived from the physics of the mixtures. The non-Gaussian distribution of the errors is taken into account to comply with the maximum likelihood. Thus, a solid theoretical framework is established to avoid current issues encountered when peak ratios are utilized. Benefits of this method include firstly, a complete management of the uncertainties on the proportions of end-members and on each individual peak ratio employed. In addition to minimization of ‘calibration' lab mixtures, elimination of manual peak selection (sometimes subjective). Finally, with this methodology employed heir in there is theoretically, no limitation on the number of end-members.
In this paper we demonstrate our approach applied successfully on a series of case studies including biodegraded oils and ‘annoyingly' similar fluids. We demonstrate that our approach can be successfully and cost-effectively applied to allow for more reliable reservoir/field management.