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Collaborating Authors
Results
Patrick W. M. Corbett started in the industry in 1978 at Unocal and worked in various positions in international (United Kingdom, the Netherlands, and Indonesia) exploration and development geoscience. Since coming to Heriot-Watt University in 1989, his research focus has been on the integration of geoscience and engineering through geologic analysis, petrophysical measurement, permeability anisotropy modeling, well test interpretation, dynamic upscaling, and genetic petrophysics. Corbett graduated with a degree in geology (Exeter University, 1977), followed by an MSc in micropalaeontology (University College London, 1978), a postgraduate diploma in geological statistics (Kingston University, 1982), and a PhD and DSc in petroleum engineering and petroleum geoengineering (both from Heriot-Watt University, 1993 and 2006, respectively). Soc., IAS, PESGB, SCA, SEPM, SPE, and SPWLA, and is a Chartered Geologist, and a Chartered Scientist. He has coauthored the books Statistics for Petroleum Engineers and Geoscientists and Cores from the Northwest European Hydrocarbon Province.
- Asia (0.91)
- Europe > United Kingdom (0.49)
- Europe > Netherlands (0.49)
- Personal (0.70)
- Instructional Material > Course Syllabus & Notes (0.48)
- Europe > Netherlands (0.89)
- Asia > Indonesia (0.89)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.70)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (0.55)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.55)
- Information Technology > Communications > Collaboration (0.50)
- Information Technology > Knowledge Management (0.40)
Experimental Investigation and Modeling of a Nanoparticle-Based Foam: Core Scale Performance for Enhanced Oil Recovery
Ahmadi, Khashayar (Memorial University) | Akrong, Dorcas Annung (Memorial University) | Sripal, Edison Amirtharaj (Memorial University) | Sahari Moghaddam, Farzan (Memorial University) | Ovwigho, Ejiro Kenneth (Memorial University) | Esene, Cleverson (Memorial University) | Machale, Jinesh (Memorial University) | Telmadarreie, Ali (CNERGREEN) | James, Lesley Anne (Memorial University)
Abstract Nanoparticle-based foam shows promise to enhance oil recovery; however, there is limited experimental investigation on the influence of injection sequence on recovery. The objective of the present study is to systematically compare the injection sequence of SiO2 nanoparticle-based foam, viz, brine-gas-foam-gas (N2) and brine-foam-brine, using core flooding experimental and simulation analyses. Relative permeability endpoints and Corey exponents are found by history matching the experimental production data using a commercial software. To match foam parameters and assess recovery considering underlying physics a software was used. Three coreflooding experiments using a novel nanoparticle-based foam were conducted on two unaged and one aged sandstone cores to investigate two injection sequences (i.e., water (brine)-gas-foam-gas and water-foam-water) at reservoir conditions. The stability and solubility of the nanofoam were studied in high-pressure and high-temperature interfacial tension experiments. Experimental results indicate that the water (brine)-gas-foam-gas sequence results in higher recovery at core scale with a 13.2% increase in recovery after foam injection and total recovery of 80.2% after respective injections of 2.0, 1.8, 1.2 and 0.5 PV of water-gas-foam-gas. The water-foam-water sequence results in a 4.4% increase in recovery after foam injection and total recovery of 61.6% after respective injections of 0.9, 2.9 and 2 PVs in water-wet core and a 6.6% increase after foam injection and total recovery of 73.3% after respective injections of 1.2, 0.6, and 0.6 PV (brine-foam-brine) in an oil-wet core. Increased oil recovery in all experiments ranged from 6.6 to 30.6%. Unlike previous studies, we investigate different nanofoam injection sequences in different wetting condition (aged/unaged cores). A limited number of studies for nanofoam on highly permeable sandstones (500–750 mD) have been reported. Results of this study show that the generated nanoparticle-based foam can be used to favorably control mobility and enhance oil recovery. The numerical simulation efforts led to several critical learnings on the physics of incremental oil recovery from dry-out effects of the foam, as well as the limitations of current commercial simulators in properly replicating the entire physics.
- North America > Canada (0.68)
- North America > United States > Texas (0.46)
- 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...)
Underground Rock Dissolution and Geomechanical Issues
Laouafa, F. (Institut National de l'Environnement Industriel et des Risques- INERIS) | Guo, J. (School of Mechanics and Engineering / Southwest Jiaotong University) | Quintard, M. (Université de Toulouse / Institut de Mécanique des Fluides de Toulouse)
ABSTRACT: This paper deals with the problem of the dissolution of soluble underground rocks and the geomechanical consequences such as subsidence, sinkholes and underground collapse. In this paper, the rock dissolution and the induced underground cavities are modeled using a Diffuse Interface Model. We describe briefly the method. We used to perform the transition (upscaling) from a multiphysics problem formulated at the microscopic scale level (pore-scale) to the macroscopic scale level (Darcy-scale). Rock material considered in this paper is gypsum, despite that the developed method is also suitable for more soluble rocks. The mechanical consequences of dissolution are analyzed for two theoretical configurations, i.e., lens and pillar. 1. INTRODUCTION Many problems in geomechanics such as subsidence, sinkholes and collapses, are related to the dissolution of soluble rocks. For example rock dissolution may create underground voids of large sizes, leading to a potential risk of instability or collapse, as illustrated in Fig. 1. Since dissolution of porous rocks may cause catastrophic damages, it is a major concern in geomechanics field. In many cases, dissolution is driven by an under saturated fluid flow. For instance, the subsurface water flow or hydraulic conditions through soils and rocks determines the onset conditions of geomechanical instability. Moreover, the natural or man-made hydraulic condition may evolve with time and change in space. Dissolution is also used intensively, for example in case of solution mining of salt. This industrial process extracts underground salt, by injection of fresh water through an injection well and extraction of the saturated brine at an extraction well. This process is very suitable in case of thin salt layer located at great depth. The multi-scale and multiphysics features of rock dissolution problem raise many questions. The first of them concerns the accuracy needed in the description of solid-liquid interface recession at the macro-scale level (Darcy-scale). To achieve this goal, a precise mathematical formalization of physicochemical and transport mechanisms at the micro-scale level is required. The second one is linked to the description of dissolution at large spatial scale (in situ scale, site scale). The third one deals with strong physical couplings with other processes, in particular, mechanical behaviors of rocks.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Sulfate > Gypsum (0.30)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (0.89)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (0.70)
Abstract Nandurdikar and Wallace's (2011) review of nearly 150 major capital projects showed that the industry is actually delivering only 75% of the production volumes forecast at the time of project sanction overall and those projects with identified subsurface issues delivered only 55% of the forecast volumes. In other words, the industry production forecasts are significantly optimistic. There are a variety of factors that contribute to the optimistic forecasts. The most important are areal subsurface model grid size, well location optimization workflows, sparse data bias, and “pro-project sanction” management bias. Each of these individually may contribute on the order of 10-25% or so of the observed overall forecast optimism. The impact of other factors such as stochastic model parameters (e.g. semivariogram range) and vertical upscaling are significantly less important.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.94)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
Abstract The main recovery mechanism in surfactant flooding is improved microscopic displacement achieved by suppressing pore-scale capillary forces by approximately four orders of magnitude through reduction of interfacial tension (IFT). Effects on macroscopic mechanisms like capillary trapping in presence of heterogeneities or gravity segregation are normally not considered.
The influence of capillary forces on segregated flow behind the displacement front is investigated by numerical simulations in homogeneous and heterogeneous models and by steady-state upscaling. The positive effect of gravity segregation is that oil floats up, accumulates under low permeable cap rocks and thereby increases the effective horizontal oil mobility. Capillary forces act against this segregation. These mechanisms are not captured in normal coarse-gridded field models. Simulations in homogeneous layer models indicated up to 20% incremental oil production from a moderate IFT reduction (1 mN/m). More field relevant heterogeneous descriptions decreased incremental recovery down towards 5%.
Gravity segregation is observed below a critical rate, depending on phase density difference, vertical permeability and layer thickness. All pertinent parameters are combined into a dimensionless viscous-gravity ratio, Rvg. The condition for gravity segregation is Rvg<1. At lower rate the oil recovery approached an upper limit obtained from upscaling under gravity-capillary equilibrium conditions. This limit was represented in terms of the dimensionless Bond number, NB. The oil production was found to be sensitive to IFT when 0.1
- Europe (1.00)
- North America > United States > Texas (0.28)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Statfjord Group (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Cook Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Brent Group (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Summary Reservoir heterogeneities occur over a wide range of length scales, and their interaction with various transport mechanisms controls the performance of subsurface flow and transport processes. Modeling these processes at large scales requires proper scaleup of petrophysical properties that are autocorrelated or heterogeneously distributed in space, and analyzing their interaction with underlying transport mechanisms. A method is proposed to investigate and quantify the uncertainty in reservoir models introduced by scaleup. It is demonstrated that when the volume support of the measurement is smaller than the representative elementary volume (REV) scale of the attribute to be modeled, there is uncertainty in the conditioning data because of scaleup and that uncertainty has to be propagated to spatial models for the attribute. This important consideration is demonstrated for mapping total porosity for a carbonate reservoir in the Gulf of Mexico. The results demonstrate that in most cases, the uncertainty distributions obtained by accounting for the scaleup procedure successfully characterize the variability in the actual core and log data observed along new wells. Conventional reservoir models considering the well data as "hard" conditioning data fail to predict the "true" values. Following this discussion on scaling of reservoir attributes, a conceptual understanding of the scaling characteristics of flow responses such as recovery factor (RF) is provided, in terms of the mean and variance of RF at different length scales. Finally, a new technique is presented to systematically quantify the scaling characteristics of transport processes by accounting for subscale heterogeneities and their interaction with various transport mechanisms based on the volume averaging approach. The objective is to provide a tool for understanding the scaling relationships for RF using detailed fine-scale compositional reservoir simulations over a subdomain of the reservoir.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.28)
- Research Report > New Finding (0.66)
- Overview > Innovation (0.48)
Abstract Increasing demand of oil and gas worldwide is promoting a new, fast growth in the oil industry where the presence of experienced engineers is limited. Exploration for hydrocarbons is reaching limiting frontiers and the near future and long term challenge will be to maximize recovery from the existing fields. Enhanced oil recovery offers an alternative to improve recovery by means of introducing an external agent which enhances oil sweeping at a pore level scale. While the EOR concept is not new; field implementation has been scarce. As a consequence the physics governing the displacement processes have not been completely understood, posing a challenge for the design and modeling of the process. This is enhanced when dealing with numerical models, which, typically are designed for primary and/or secondary depletion processes, with grid orientations and dimensions suitable for these field conditions. Very often though, these same models are used to design and evaluate the potential for field EOR. This paper addresses the main challenges of modeling the fine scale displacement mechanism with a full field model, highlighting the typical errors in recovery efficiency that can occur and suggesting scales at which screening models can be built. Displacement processes in the reservoir are dominated by the combination of the viscous and capillary forces, the efficiency and ultimately the amount of displaced oil is controlled by the balance of these forces. During a core scale displacement process, viscous forces are dominant and most of the oil is contacted by the injected agent. This displacing mechanism is different from the one experienced at reservoir conditions where gravity forces play an important role, influencing the amount of oil which is contacted by the EOR agent, where under and overrunning may occur. Modeling of these displacements requires a greater resolution than the one used in for the full field model. The impact of model size and force balance during an EOR displacement process is presented is this paper.
- North America > United States (0.46)
- Asia (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (0.93)
Regional Upscaling: A New Method To Upscale Waterflooding in Heterogeneous Reservoirs for a Range of Capillary and Gravity Effects
Coll, C. (PDVSA S.A.) | Muggeridge, A.H. (Centre for Petroleum Studies, Imperial College, London) | Jing, X.D. (Centre for Petroleum Studies, Imperial College, and Shell Intl.)
Summary This paper presents a new, two-phase upscaling methodology hereafter referred to as "regional" upscaling. A fine-grid flow simulation is performed on a representative section of the reservoir. Dimensionless numbers are then calculated for each fine-grid cell to determine the dominant flow regime in that cell. The coarse grid is selected based upon the spatial locations of the different force regimes observed in the fine-grid simulation model. Two-phase upscaling is then performed from the fine to the coarse grid using the most appropriate pseudoization technique [Kyte and Berry or vertical equilibrium (VE)] for the dominant flow regime in each region. The method is compared with different global pseudoization methods and its accuracy examined for a range of different heterogeneity models, including one for a reservoir in Lake Maracaibo in western Venezuela. Introduction Waterflood sweep efficiency is a function of the prevailing flow regime and the reservoir heterogeneity. Recent work has shown that different styles of reservoir heterogeneity (fluvial, wave-dominated, and tidal) affect oil recovery in different ways and that all length scales of heterogeneity have a significant impact on oil recovery. However, small-scale heterogeneities cannot be represented explicitly in field-scale simulation models because of limitations in computer speed and memory. Therefore, effective permeabilities and pseudorelative permeabilities are used to represent the average effects of small-scale heterogeneity on the large-scale flow. Although single-phase upscaling is fairly well understood, this is not the case for two-phase upscaling. Many different methods for developing pseudorelative permeabilities are reported in the literature, and it appears that the best pseudoization method to use for a particular problem will depend upon the flow regime. For example, vertical equilibrium will apply for gravity- or capillary gravity- dominated displacements; steady-state pseudos can be used for capillary-dominated flows, and dynamic methods are usually used for viscous-dominated flows. In homogeneous reservoirs, the dominant flow regime can be determined from examination of the relevant dimensionless numbers. In heterogeneous reservoirs, the flow rate will vary with permeability, so different flow regimes may prevail in different parts of the reservoir. In these circumstances, the overall flow regime determined from dimensionless numbers using effective properties and mean flow rates may not actually be the dominant flow regime in the reservoir. If two-phase upscaling techniques are then selected based on the values of these "global" dimensionless numbers, this may result in incorrect flow modeling on the large scale. A new concept of "local" dimensionless numbers is presented to help determine local flow regimes in heterogeneous reservoirs. Based on these conditions, we can derive what we may call "force maps," which describe the dominant forces operating in different parts of the reservoir. This information can then be used to select the best coarse-grid model for upscaling and the most appropriate upscaling technique for the heterogeneity/flow regime in question. The method is applied to a series of synthetic models of small-scale heterogeneity, typical of a range of depositional environments. It is then tested on a sector model of a reservoir in western Venezuela's Lake Maracaibo Basin with very promising results. Global Dimensionless Numbers The relative importance of viscous, capillary, and gravity forces on reservoir flow is usually characterized in terms of the gravity-to-viscous ratio, Ngv, and the capillary-to-viscous ratio, NPcv. There are many different definitions of these dimensionless numbers reported in the literature. In this paper we shall use those derived by Shook et al.Equation 1 andEquation 2 where Kx, UT, ?r0, ??, H, L, f, s, and a are, respectively, absolute permeability in the x direction, total fluid velocity, the endpoint mobility of the oil phase, fluid density difference, reservoir thickness, reservoir length, porosity, interfacial tension, and dip angle. The standard procedure to estimate which forces are controlling the flow in heterogeneous reservoirs has been to estimate each of the numbers (NPcv and Ngv) using effective properties for the entire reservoir. From Eqs. 1 and 2 we see that these numbers are dependent on various parameters that can vary spatially within the reservoir - permeability, the endpoint oil mobility, and interfacial tension. These in turn will cause nonuniform flow rates (over and above any geometrical effects due to well positions) across the reservoir. It is clear that in heterogeneous reservoirs, the dominant flow regime will vary across the reservoir. As a result, it is likely that water breakthrough time and overall recovery will not just be a function of Ngv and NPcv, but will also depend upon the style and magnitude of heterogeneity within the reservoir. We shall demonstrate that this is indeed the case using 2D models of different types of small-scale heterogeneity. Heterogeneity and Recovery Small-Scale Models. Three different sedimentary structures and facies related to shallow marine, coastal, and continental depositional environments were selected as base examples to study the relationship between small-scale heterogeneity and flow regime: bioturbated, parallel lamination with bioturbation, and horizontal laminae.
- Europe (1.00)
- South America > Venezuela > Zulia > Maracaibo (0.44)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract The Smørbukk Field comprises a deep, very heterogeneous reservoir with variable fluids (gas condensate to light oil). This study presents a series of sensitivity studies to evaluate the effect of different geological parameters and development options on oil production and gas oil ratio within a sector of that field. The black-oil Eclipse reservoir simulator is used to represent the gas displacing oil behavior of this rather complex reservoir. Constant production rates and pressure controls are assumed. Detailed geological models of sedimentary and structural heterogeneity were used to define reservoir simulation models with upscaled permeabilities and relative permeabilites. Displacement and transmissibility reduction across faults were explicitly modeled and compared with simpler assumptions. The main performance measure used is oil recovery and GOR at the five year production point. Important interactions between geological assumptions and fluid rates and pressures were identified and used to identify the most promising production strategy. Introduction Our aim in this study is to evaluate the geological factors affecting production performance in Sm rbukk gas condensate field. We focus on a 25m thick reservoir unit (Tilje 1.1) which contains an important oil leg from which maximum early oil production is important to the overall field economics. The reservoir is challenging, as it is deep (4100m to 4800m) and heterogeneous in both rock properties and fluid composition. We used the Eclipse Black Oil simulator with the live oil / wet gas and (instantaneous) vaporized oil options. The initial fluid distribution is represented by a vertically varying bubble point and dew point curve and a gas/oil contact at 4710m. The aquifer is assumed to be inactive. Our main questions are as follows:What is the effect of thin-bedded and diagenetic reservoir heterogeneity on production? How do the fluid and rock properties assumed affect mobility of the gas displacing oil system? How would (uncertain) faults and fault compartments affect production? How are different production scenarios (numbers of wells and flow rates) affected by reservoir assumptions? These questions are interrelated, and in the reservoir simulations all these factors are coupled (heterogeneity models, relative permeability models, upscaling effects, fault models, and production scenarios). A more general analysis of effects tidal deltaic reservoir heterogeneity on production is given in refs. 1 and 2. The sensitivity studies attempt to isolate the key interactions and identify the most important effects. The work was done in two main stages:Upscaling studies: These focused on upscaling methods and the correct representation of heterogeneity effects on flow simulation models. This was done on a smaller ‘sub-sector’ model (area of about 6km by 2.2km) with a simple production pattern (one injector and one producer). Multi-scale geological modeling (using the programs TBED and RMS-Storm) and steady state upscaling methods were used. Results of this work are reported elsewhere. Production impact studies: These built on the first stage results but focused on different production patterns and the effect of fault compartments and seals. This was done on a larger ‘full-sector’ model (area of about 6km by 7km). Figure 1 shows the cases considered in this second stage. Figure 2 shows the total production profiles for the base case (explained below) illustrating gradual leveling off of oil production and the steady rise in GOR characteristic of this very heterogeneous reservoir.
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Tilje Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
This paper (SPE 50992) was revised for publication from paper SPE 37986, first presented at the 1997 SPE Reservoir Simulation Symposium held in Dallas, 8-11 June. Original manuscript received for review 10 July 1997. Revised manuscript received 10 February 1998. Revised manuscript approved 3 March 1998. Summary Single-phase upscaling techniques have been in use for a number of years now to incorporate subgrid reservoir description information into reservoir simulation. There have also been a number of approaches to developing tow-phase upscaling algorithms suitable for black oil simulation. The key barrier to the development of compositional upscaling techniques is algorithm speed. A straightforward extension of existing two-phase upscaling approaches would consume enormous amounts of computer time because of the number of additional components modeled and the need to perform flash calculations. This paper describes an upscaling method for simulations in which compositional processes play a key role, such as miscible gas injection or gas cycling schemes. We will describe the method to generate upscaled compositional fluxes in two or three dimensions, and the way in which the upscaled fluxes are incorporated into a compositional simulator. Our approach uses a streamline technique, which provides a tremendous gain in speed for the loss of a small amount of accuracy. The streamline technique produces upscaled fluxes almost identical to those obtained from postprocessing conventional compositional model runs in a fraction of the time. The results of applying these upscaled fluxes in a realistic example show that we can obtain close agreement between fine and coarse grid models of lean gas injection into oil at residual saturation. For an example problem with a 12-component equation of state (EOS), the component recovery curves with upscaled fluxes on a 5 x 5 grid agree well with the original 100 x 20 fine grid. P. 272
- North America > United States (1.00)
- Europe (1.00)