bluuebunny/crossref_metadata_2025 huggingface dataset:
Advanced Casing Design With Finite-Element Model of Effective Dogleg Severity, Radial Displacements, and Bending Loads
Authors: McSpadden A.R.. R. , Coker III O.D.. D. , Ruan G.C. C
Published: November 2012

A purpose-built finite-element model (FEM) is applied to simulate radial displacement of a casing string constrained within an outer wellbore. The FEM represents a fully stiff-string model wherein the casing is approximated by general-beam elements with six degrees of freedom at each node to account for all possible physical displacements and rotations. Results predicted include deflection of the casing centerline from the wellbore centerline, effective dogleg curvature, bending deformation, wall-contact forces, and bending-stress magnification. These results will provide for a more-accurate assessment of well integrity in terms of casing-stress safety factors and centralization before cementing, as well as more accurate prediction of running loads during the drilling phase.

In critical-well-casing design, accurate assumptions regarding bending stiffness may be necessary to avoid overly conservative as well as nonconservative analysis. Challenging finite high-pressure/ high-temperature (HP/HT) and extreme-temperature wells are opportunities for increased design efficiency by avoiding overly conservative and costly designs, which can be crucial. Alternatively, design for extreme loads such as overpull loads in long deviated wells may be nonconservative if severe bending stresses are not considered.

A realistic case study is presented that demonstrates the possibility to achieve cost efficiency by means of optimized casing design. A case study also is presented in which a nonconservative design may result if severe bending loads are not modeled. The purpose-built FEM code is in many ways preferable to the use of commercial finite-element-analysis (FEA) packages because of the time-consuming effort required to build up the detailed model.

In typical casing and tubular-stress design, a soft-string model assumes casing strings are coincident with the wellbore centerline. The known or assumed wellbore curvature is applied directly to the casing string. Any effect of casing-string stiffness and allowable radial displacement within the outer wellbore is ignored. In many cases, this results in an overly conservative analysis. Likewise, the impact of bending-stress magnification is typically ignored, along with the effects of centralizer placement. This may also be nonconservative for critical overpull situations, such as in extended-reach-drilling (ERD) and horizontal wells.
Enhanced-Velocity-Multiblock Method for Coupled Flow and Reactive-Species Transport Through Porous Media: Applications to Bioremediation and Carbon Sequestration
Authors: Thomas S.G.. G. , Wheeler M.F.. F.
Published: November 2012

This paper presents a multiblock-discretization method—the enhanced-velocity mixed-finite-element method (EVMFEM) (Wheeler et al. 2002)—for coupled multiphase flow and reactive-species-transport modeling in porous-media applications. The method provides local mass balance and a continuous approximation of fluxes across interfaces of elements and subdomains. It can treat nonmatching grids, allowing for a flexible choice of grid refinements. Further, by distributing the blocks among processors such that each block has approximately the same number of elements, this method can be implemented efficiently in parallel, thereby offering further reductions in computational cost.

The paper also presents recent application of EVMFEM to challenging problems such as compositional flow simulations of CO2 sequestration. Tests with EVMFEM suggest that it is advantageous to apply grid refinements around wells and to areas in which dynamics of chemical-species concentration is highest. Allowing for variable grid refinements greatly reduces the simulation cost, while preserving overall accuracy of the solution. For completeness, a few significant analytic results on convergence of the method are stated and referenced, omitting proof.

This work is significant in advancing the discretization and application of EVMFEMs in reservoir-simulation development. Problems such as transport of chemical species in multiphase flow and CO2 sequestration have begun to assume significant importance in decisions regarding the preservation of our environment and in the safe and reliable means of delivering energy. This paper offers useful methods and some innovative future directions to address the huge computational costs involved in solving such complex problems.
Accurate and Efficient Simulation of Multiphase Flow in a Heterogeneous Reservoir With Error Estimate and Control in the Multiscale Finite-Volume Framework
Authors: Hajibeygi H.. , Lee S.H.. H. , Lunati I..
Published: November 2012

The multiscale finite-volume (MSFV) method is designed to reduce the computational cost of elliptic and parabolic problems with highly heterogeneous anisotropic coefficients. The reduction is achieved by splitting the original global problem into a set of local problems (with approximate local boundary conditions) coupled by a coarse global problem. It has been shown recently that the numerical errors in MSFV results can be reduced systematically with an iterative procedure that provides a conservative velocity field after any iteration step. The iterative MSFV (i-MSFV) method can be derived with an improved (smoothed) multiscale solution to enhance the localization conditions, with a Krylov subspace method [e.g., the generalized-minimal-residual (GMRES) algorithm] preconditioned by the MSFV system, or with a combination of both. In a multiphase-flow system, a balance between accuracy and computational efficiency should be achieved by finding a minimum number of i-MSFV iterations (on pressure), which is necessary to achieve the desired accuracy in the saturation solution. In this work, we extend the i-MSFV method to sequential implicit simulation of time-dependent problems. To control the error of the coupled saturation/pressure system, we analyze the transport error caused by an approximate velocity field. We then propose an error-control strategy on the basis of the residual of the pressure equation. At the beginning of simulation, the pressure solution is iterated until a specified accuracy is achieved. To minimize the number of iterations in a multiphase-flow problem, the solution at the previous timestep is used to improve the localization assumption at the current timestep. Additional iterations are used only when the residual becomes larger than a specified threshold value. Numerical results show that only a few iterations on average are necessary to improve the MSFV results significantly, even for very challenging problems. Therefore, the proposed adaptive strategy yields efficient and accurate simulation of multiphase flow in heterogeneous porous media.
Combining Elastic and Plastic Fatigue Damage in Steel Pipelines, Risers, and Coiled Tubing
Authors: Bridge C.D.. D.
Published: November 2012

Coiled tubing is a continuous pipe that, having been coiled around a reel for storage, can be deployed and used as a pipeline or riser. During deployment as a riser, the coiled tubing is unspooled from the reel, run into the water, and connected to the wellhead. This process plastically strains the pipe, causing plastic (or low-cycle) fatigue damage. When the coiled tubing is connected to the wellhead, the environmental loading causes elastic-stress cycles, resulting in elastic (or high-cycle) fatigue damage.

Numerous methods are available to determine fatigue life from either plastic or elastic cycling; however, few data are available within the industry on how the fatigue damages from elastic and plastic cycles combine.

This paper presents the experimental work conducted to show the combined fatigue life of notched samples of flat steel used to manufacture coiled tubing that has been plastically and elastically cycled. The data show that the combined fatigue life can be lower than the total of the plastic and elastic fatigue damages by use of Miner's rule. Existing theory suggests that the combined fatigue life could be as low as 10% of the Miner's-rule fatigue damages; however, the experimental data indicate that a more appropriate value is closer to 75%.
Assessing Well-Integrity Risk: A Qualitative Model
Authors: Dethlefs J.C.. C. , Chastain B..
Published: November 2012

For successful delivery of well integrity (WI), there needs to be an understanding of the risks that can cause undesirable events such as safety hazards or loss of containment. Performing a risk assessment (RA) on a well, or type of well, will help determine and rank the potential risks and provide information that allows limited resources to be applied in the most effective manner. The main objectives of performing a risk assessment include (a) following a formal process to assess risk consistently and to enable comparison between well-barrier failure-mode scenarios; (b) qualitatively assessing well-barrier failure risk for every segment of a well; (c) documenting suggestions that are offered by the riskassessment team for mitigating well-barrier failure risk; and (d) providing a report of the methodology, failure-mode scenarios, risk ranking, and potential mitigation actions for use as a reference tool for managing WI on a routine basis.

Our WI/RA model follows a common qualitative risk-assessment process—a team-based, structured brainstorming format, using the "What-If Methodology" to identify potential hazards associated with well-barrier failure modes. In addition, the model has the following attributes: It incorporates a unique method to segment well barriers into discrete sections, successively "failing" each section for evaluation. The list of analyzed well-barrier failure modes, along with their risk ranking, becomes the risk register for the well or type of well.It is adaptable for assessing well-barrier failure modes on a single well, or a group of wells, having the same general design parameters. An entire well portfolio can be assessed quickly by analyzing types of wells rather than individual wells.It can be used to assess well-barrier failure risk for any type of well.The model can easily be modified to conform to any company's risk model.The WI/RA model has been proven toSuccessfully assess well-barrier failure risk for thousands of wellsFocus specifically on well-barrier failure modes, and as a result be an effective tool that should be incorporated into a "best-in-class" WI programBe used as a management tool to provide guidance for how limited resources can be used effectively to continuously deliver WI.
Negative-Saturation Approach for Compositional Flow Simulations of Mixed CO2/Water Injection Into Geothermal Reservoirs Including Phase Appearance and Disappearance
Authors: Salimi Hamidreza , Wolf Karl-Heinz , Bruining Johannes
Published: November 2012

Cold mixed CO2/water injection into hot-water reservoirs can be used for simultaneous geothermal-energy (heat) production and subsurface CO2 storage. This paper studies this process in a 2D geothermal homogeneous reservoir, a layered reservoir, and a heterogeneous reservoir represented by a stochastic-random field. We give a set of simulations for a variety of CO2/water-injection ratios. In this process, often regions of two-phase flow are connected to regions of single-phase flow. Different systems of equations apply for single-phase and two-phase regions. We develop a solution approach, called the nonisothermal-negative-saturation (NegSat) solution approach, to solve efficiently nonisothermal compositional flow problems (e.g., CO2/water injection into geothermal reservoirs) that involve phase appearance, phase disappearance, and phase transitions. The advantage of this solution approach is that it circumvents using different equations for single-phase and two-phase regions and the ensuing unstable switching procedure. In the NegSat approach, a single-phase multicomponent fluid is replaced by an equivalent fictitious two-phase fluid with specific properties. The equivalent properties are such that the extended saturation of a fictitious gas is negative in the single-phase aqueous region.

We discuss the salient features of the simulations in detail. When two phases are present at the injection side, heterogeneity and layering lead to more CO2 storage compared with the homogeneous case because of capillary trapping. In addition, layering avoids movement of the CO2 to the upper part of the reservoir and thus reduces the risk of leakage. Our results also show that heterogeneity and layering change the character of the solution in terms of useful-energy production and CO2 storage. The simulations can be used to construct a plot of the recovered useful energy vs. maximally stored CO2. Increasing the amount of CO2 in the injection mixture leads to bifurcation points at which the character of the solution in terms of energy production and CO2 storage changes. For overall injected-CO2 mole fractions less than 0.04, the result with gravity is the same as the result without gravity. For larger overall injected-CO2 mole fractions, however, the plot without gravity differs from the plot with gravity because of early breakthrough of a supercritical-CO2 tongue near the caprock. The plot of the useful energy (exergy) vs. the CO2-storage capacity in the presence of gravity shows a Z-shape. The top horizontal part represents a branch of high exergy recovery and a relatively lower storage capacity, whereas the bottom part represents a branch of lower exergy recovery and a higher storage capacity.
Use of Pressure/Rate Deconvolution To Estimate Connected Reservoir-Drainage Volume in Naturally Fractured Unconventional-Gas Reservoirs From Canadian Rockies Foothills
Authors: Chen Andrew , Jones Jack R.
Published: November 2012

Case studies are presented in this paper to demonstrate the use of the pressure/rate deconvolution-approach in estimating drainage areas for wells completed in some of the naturally fractured tight gas reservoirs of the Canadian Rockies foothills. These case studies demonstrate the application of deconvolution to two key carbonate-stratigraphical horizons in the area: the Triassic Baldonnel and the Permo-Carboniferous Taylor Flat formations. In these structural plays with significant areal formation-rock heterogeneity, the matrix-rock properties controlling the gas storativity are low, with porosity between 3 and 6%, causing low matrix-rock permeability (from 0.01 and 0.1 md). However, all of these formations have been thrusted, overturned, and subjected to reverse faulting. These diagenetic factors have created swarms of natural fractures that control flow rates and may define rock volumes connected to individual wells.

In each well, a preproduction flow test was performed with the intent of ensuring acceptable flow rates and scoping facility design. At this stage of early development, initial-gas-in-place (IGIP) estimates were derived mainly from geophysical mapping, with plans to calibrate the IGIP number through the application of gas material balance, rate-transient analysis, and/or simple late-time rate decline. The rate-history data available in the early stage of production were integrated with pressure-buildup (PBU) data collected later in the production life of the well during annual or routine shut-in periods that were relatively short. Application of deconvolution in this paper is aimed at detecting early signs of pseudosteady-state pool depletion and estimating connected drainage volume. The deconvolution procedures help calibrate and/or reconcile geosciences-defined volumetric resource sizes, map remaining reserves, and help identify possible infill-drilling opportunities.
A Proposed Method for Planning the Best Initial Response to Kicks Taken During Managed-Pressure-Drilling Operations
Authors: Smith J.R.. R. , Patel B.M.. M.
Published: November 2012

An industry-supported research project has investigated well-control methods for managed-pressure drilling (MPD) using the constant-bottomhole-pressure (CBHP) method. This paper proposes a method for planning the best initial response to be used when a kick occurs during CBHP MPD on the basis of conclusions from the research. That research (Davoudi et al. 2010) concluded that the three most widely applicable initial responses to kicks during MPD were increasing casing pressure until flow out equals flow in, shutting the well in, and using an adaptation of an MPD-pump shutdown schedule to detect and shut in a low-rate kick. Increasing pump rate until flow out equals flow in was concluded to have limited, but potentially still important, applications.

The proposed method uses a decision tree during the planning phase of a well to select the best kick response to be used for each hole interval for inclusion in the drilling program. This selection is based on the desired tolerance to kicks, equipment being used, well geometry, and conclusiveness of the kick warning signs. The equations necessary to calculate decision parameters, example calculations for an application of the decision tree, and comparison of simulation results to application of the decision tree are included. The decision tree indicates the response that maximizes kick tolerance within the well design, gives a basis for revising equipment or well design to maximize kick tolerance, and supports calculation of the expected kick-tolerance advantage of the increasing-casing-pressure response vs. a shut-in response.
Bayesian Optimization Algorithm Applied to Uncertainty Quantification
Authors: Abdollahzadeh Asaad , Reynolds Alan , Christie Mike , Corne David , Davies Brian , Williams Glyn
Published: November 2012

Prudent decision making in subsurface assets requires reservoir uncertainty quantification. In a typical uncertainty-quantification study, reservoir models must be updated using the observed response from the reservoir by a process known as history matching. This involves solving an inverse problem, finding reservoir models that produce, under simulation, a similar response to that of the real reservoir. However, this requires multiple expensive multiphase-flow simulations. Thus, uncertainty-quantification studies employ optimization techniques to find acceptable models to be used in prediction. Different optimization algorithms and search strategies are presented in the literature, but they are generally unsatisfactory because of slow convergence to the optimal regions of the global search space, and, more importantly, failure in finding multiple acceptable reservoir models. In this context, a new approach is offered by estimation-of-distribution algorithms (EDAs). EDAs are population-based algorithms that use models to estimate the probability distribution of promising solutions and then generate new candidate solutions.

This paper explores the application of EDAs, including univariate and multivariate models. We discuss two histogram-based univariate models and one multivariate model, the Bayesian optimization algorithm (BOA), which employs Bayesian networks for modeling. By considering possible interactions between variables and exploiting explicitly stored knowledge of such interactions, EDAs can accelerate the search process while preserving search diversity. Unlike most existing approaches applied to uncertainty quantification, the Bayesian network allows the BOA to build solutions using flexible rules learned from the models obtained, rather than fixed rules, leading to better solutions and improved convergence. The BOA is naturally suited to finding good solutions in complex high-dimensional spaces, such as those typical in reservoir-uncertainty quantification.

We demonstrate the effectiveness of EDA by applying the well-known synthetic PUNQ-S3 case with multiple wells. This allows us to verify the methodology in a well-controlled case. Results show better estimation of uncertainty when compared with some other traditional population-based algorithms.
New Analytical and Statistical Approach for Estimating and Analyzing Sand Production Through Wire-Wrap Screens During a Sand-Retention Test
Authors: Chanpura Rajesh A. , Fidan Selcuk , Mondal Somnath , Andrews Jamie S. , Martin Frederic , Hodge Richard M. , Ayoub Joseph A. , Parlar Mehmet , Sharma Mukul M.
Published: November 2012

A slurry-type sand-retention test (SRT) that simulates gradual rock failure around the wellbore has been used widely in the industry to evaluate the performance of sand-control screens for standalone-screen (SAS) applications. Using the test results, screen selection is achieved generally on the basis of the relative ranking of screen performances rather than absolute performance.

Chanpura et al. (2011) highlighted recently the drawbacks of the current practices in slurry-type SRT procedures and proposed a new testing and interpretation methodology. Mondal et al. (2011) proposed simulation methods and results that, to the best of our knowledge, modeled screen performance numerically for the first time and presented comparisons to physical experiments. However, the approach used by Mondal et al. (2011) considers cases in which hole collapse occurs on wire-wrap screens (WWSs) and simulates "prepack" testing as opposed to the slurry-type tests considered in this work.

In this paper, we present an analytical and a numerical [Monte Carlo (MC)] approach for the prediction of sand production through sand screens with slot geometry. We show that the proposed methods can estimate both mass and size distribution of the produced solids in a slurry-type SRT, taking into account the full particle-size distribution (PSD) of formation sand for WWSs. Simulations show that once the slot opening is covered by particles larger than the slot opening, sand production becomes negligible unless there is a true "fines" problem, which is characterized by a bimodal size distribution. The effect of slot-size variation in screen coupons on sand production demonstrates the importance of proper quality control or at least accurate determination of slot sizes in these tests. The proposed methods can be used to estimate sand production in slurry-type SRTs for different screen sizes and thereby can enable screen-size selection on the basis of a defined acceptable level of sand production. Final screen selection can be confirmed through an SRT.
An Improved Technique for Interpreting Perforating-Flow-Laboratory Results: Honoring Observed Cleanup Mechanisms
Authors: Grove B.. , Harvey J.. , Zhan L.. , Atwood D..
Published: November 2012

Perforating-laboratory experiments can be a useful element of field-perforating-job design. In some instances, the goal is to qualitatively compare multiple candidate perforating techniques. In others, the goal is to obtain quantitative insight into likely flow performance in the field. Although the laboratory will never perfectly replicate the downhole environment, it can yield useful results, which—if properly interpreted—can enable informed prediction of downhole-flow performance.

A traditional flow-laboratory experiment (API RP 19B 2006) yields numerous key results, four of which are required inputs to downhole-inflow simulators. These are perforation-tunnel length and diameter, crushed-zone thickness, and permeability. In the case of natural perforated completions as opposed to stimulated completions (e.g., hydraulically fractured or sand control), these parameters (in addition to other system and wellbore parameters) dictate the skin and ultimate flow performance of the completion.

Crushed-zone permeability is typically inferred from core-flow efficiency (CFE) and an assumed crushed-zone thickness. Traditionally applied, this technique can yield values that are inaccurate, and can produce misleading predictions of downhole performance more significantly.

To address this, we have developed new methods for both measuring and interpreting CFE. The new measurement technique yields CFE values that we show to be more meaningful and relevant. The new interpretation technique provides a consistent method of translating CFE to crushed-zone permeability, and is capable of accounting for the effect of partially plugged tunnels. This work clarifies and improves the link between laboratory and field performance of perforators, with the ultimate goal of increasing the value of downhole-inflow-performance predictions.

While other work is ongoing to challenge the framework of the conventional skin models, the present paper accepts these models as a premise. This work simply presents a coherent methodology of interpreting laboratory data, with the intent of generating the required inputs for skin models as they currently exist. Furthermore, it is recommended that this workflow be considered for inclusion in any revisions to the API Section 4 (API RP 19B 2006) testing protocol.
Diagnosis of Acid Placement From Temperature Profiles
Authors: Tan X.. , Tabatabaei M.. , Zhu D.. , Hill A.D.. D.
Published: November 2012

Optimum fluid placement is crucial for a successful acid-stimulation treatment, both for horizontal wells where there is a broad variation of reservoir properties along the wellbore and for vertical wells with multiple zones and/or extensive productive intervals. Recently, distributed-temperature-sensing technology has enabled us to observe dynamic temperature profiles along a wellbore during and after an acid treatment. This technology allows us to monitor and evaluate treatments in real time by capturing a sequence of temperature profiles at different times and inverting temperature response to acid-injection profiles.

We have developed mathematical models to simulate the temperature behavior along a wellbore, horizontal or vertical, during and just after an acid treatment. This approach couples a wellbore model and a near-wellbore formation thermal model considering the effects of both mass and heat transfer between the wellbore and the formation. The models account for all significant thermal processes involved during a treatment, including heat of reaction, conduction, and convection. An inversion procedure is applied to interpret the acid-distribution profiles from the measured temperature profiles.

For horizontal wells, the results indicate that the distribution of stimulation fluid along a lateral and the effectiveness of diversion processes during an acid treatment can be quantified in real time using distributed-temperature measurements. The model shows that the relative injectivities into different zones can be interpreted from the temperature response measured during injection. For vertical wells, we have focused on diagnosing the volume of acid placed in each zone from the flowback temperature history. During the flowback period, the zones that have taken more acid volume will show more heating because of reaction and will have higher temperature when hotter fluid enters the wellbore. This provides a mechanism to quantitatively determine the acid distribution. The methods developed from this study can help to diagnose and optimize acidizing design, and improve the efficiency of acid stimulation.
Determining Shale Permeability to Gas by Simultaneous Analysis of Various Pressure Tests
Authors: Civan F.. , Rai C.S.. S. , Sondergeld C.H.. H.
Published: November 2012

A model-assisted analysis is presented of pressure-pulse-transmission data obtained under different pressure conditions with core plugs of shale-gas formations. Applications and validations for steady-state and transient-state laboratory tests are provided. Best-estimate values of the intrinsic permeability and tortuosity at a reference condition and the Langmuir volume and pressure are determined by matching the solution of a modified Darcy model to several pressure-pulse-transmission flow tests with core samples simultaneously. The data-interpretation model considers the prevailing characteristics of the apparent permeability under the various flow regimes involving gas flow through extremely low-permeability core samples. Further, the present fully pressure-dependent shale-and gas-property formulation allows for model-assisted extrapolation from the reference conditions to field conditions once the unknown model parameters have been estimated under laboratory conditions. The improved method provides a better match to the measurements of the pressure tests than previous models, which assume only Darcy flow.
Use of Phase Streamlines for Covariance Localization in Ensemble Kalman Filter for Three-Phase History Matching
Authors: Watanabe Shingo , Datta-Gupta Akhil
Published: November 2012

The ensemble Kalman filter (EnKF) has gained increased popularity for history matching and continuous reservoir-model updating. It is a sequential Monte Carlo approach that works with an ensemble of reservoir models. Specifically, the method uses cross covariance between measurements and model parameters estimated from the ensemble. For practical field applications, the ensemble size needs to be kept small for computational efficiency. However, this leads to poor approximations of the cross covariance and can cause loss of geologic realism from unrealistic model updates outside the region of the data influence and/or loss of variance leading to ensemble collapse. A common approach to remedy the situation is to limit the influence of the data through covariance localization.

In this paper, we show that for three-phase-flow conditions, the region of covariance localization strongly depends on the underlying flow dynamics as well as on the particular data type that is being assimilated, for example, water cut or gas/oil ratio (GOR). This makes the traditional distance-based localizations suboptimal and, often, ineffective. Instead, we propose the use of water- and gas-phase streamlines as a means for covariance localization for water-cut- and GOR-data assimilation. The phase streamlines can be computed on the basis of individual-phase velocities which are readily available after flow simulation. Unlike the total velocity streamlines, phase streamlines can be discontinuous. We show that the discontinuities in water-phase and gas-phase streamlines naturally define the region of influence for water-cut and GOR data and provide a flow-relevant covariance localization during EnKF updating.

We first demonstrate the validity of the proposed localization approach using a waterflood example in a quarter-five-spot pattern. Specifically, we compare the phase streamline trajectories with cross-covariance maps computed using an ensemble size of 2,000 for both water-cut and GOR data. The results show a close correspondence between the time evolution of phase streamlines and the cross-covariance maps of water-cut and GOR data. A benchmark uncertainty quantification (the PUNQ-S3) (Carter 2007) model application shows that our proposed localization outperforms the distance-based localization method. The updated models show improved forecasts while preserving geologic realism.
Residual Oil Saturation Determination for EOR Projects in Means Field, a Mature West Texas Carbonate Field
Authors: Pathak Prabodh , Fitz Dale E. , Babcock Kenneth P. , Wachtman Richard J.
Published: November 2012

The technical success of an enhanced oil recovery (EOR) project depends on two main factors: first, the reservoir remaining oil saturation (ROS) after primary and secondary operations, and second, the recovery efficiency of the EOR process in mobilizing the ROS. These two interrelated parameters must be estimated before embarking on a time-consuming and costly process for designing and implementing an EOR process. The oil saturation can vary areally and vertically within the reservoir, and the distribution of the ROS will determine the success of the EOR injectants in mobilizing the remaining oil.

There are many methods for determining the oil saturation (Chang et al. 1988; Pathak et al. 1989), and these include core analysis, well-log analysis, log/inject/log (LIL) procedures (Richardson et al. 1973; Reedy 1984), and single-well chemical tracer tests (SWCTT) (Deans and Carlisle 1986). These methods have different depths of investigation and different accuracies, and they all provide valuable information about the distribution of ROS. No single method achieves the best estimate of ROS, and a combination of all these methods is essential in developing a holistic picture of oil saturation and in assessing whether the oil in place (OIP) is large enough to justify the application of an EOR process. As Teletzke et al. (2010) have shown, EOR implementation is a complex process, and a staged, disciplined approach to identifying the key uncertainties and acquiring data for alleviating the uncertainties is essential. The largest uncertainty in some cases is the ROS in the reservoir.

This paper presents the results from a fieldwide data acquisition program conducted in a west Texas carbonate reservoir to estimate ROS as part of an EOR project assessment. The Means field in west Texas has been producing for more than the past 75 years, and the producing mechanisms have included primary recovery, secondary waterflooding, and the application of a CO2 EOR process. The Means field is an excellent example of how the productive life and oil recovery can be increased by the application of new technology. The Means story is one of judicious application of appropriate EOR technology to the sustained development of a mature asset. The Means field is currently being evaluated for further expansion of the EOR process, and it was imperative to evaluate the oil saturation in the lower, previously undeveloped zones. This paper briefly outlines the production history, reservoir description, and reservoir management of the Means field, but this paper concentrates on the residual oil zone (ROZ) that underlies the main producing zone (MPZ) and describes a recent data acquisition program to evaluate the oil saturation in the ROZ. We discuss three major methods for evaluating the ROS: core analysis, LIL tests, and SWCTT tests.
Parametric Analysis of Wellbore-Strengthening Methods From Basic Rock Mechanics
Authors: Morita Nobuo , Fuh Giin-Fa
Published: November 2012

The authors presented the first industry SPE paper on wellbore strengthening, which proposed a new concept for lost-circulation prevention while drilling (Morita et al. 1988; Fuh et al. 1992; Morita et al. 1996). Recently, the authors were invited to present at the 2010 SPE Forum held at Park City, Utah, USA. This presentation focused on wellbore-strengthening methods currently used in the industry, including well cooling, stress cage, and tip screening of induced fractures. During the forum, participants requested a parametric analysis of these methods using rock-mechanics equations and principles. This paper presents a set of analytical equations developed for parametric analysis of three typical wellbore-strengthening methods (Fuh et al. 2007; Alberty and McLean 2004) and provides information about the strengths and limitations of each method. In addition, an updated set of equations developed on the basis of previous work completed by the authors has been provided to make the analysis of wellbore-strengthening methods easier to implement.

The equations can be classified by the length of the cracks to be stabilized, as follows: Borehole strengthening by heating to stabilize 0.0- to 0.1-in. cracks. (Not included in this parametric study.)Borehole strengthening to stabilize microcracks (with mudcake or fine particles) for 0.1- to 1-in. cracks.Borehole strengthening to stabilize macrocracks (stress-cage method) for 1-in. to 2-ft cracks.Borehole strengthening to stabilize a large fracture with the tip-screening method for cracks longer than 10 ft.Parametric studies were conducted on three wellbore-strengthening methods, and the following observations were made:Borehole-stabilization method: Water-based mud mixed with 25/40-mesh particles stabilizes the borehole by plugging the microcracks with mudcake. Borehole stability is enhanced by mixing 25/40-mesh crushed nut shells into the mud. Some drilling engineers enhance borehole stability by intentionally returning a proper range of cutting particles from the shale shakers.Stress-cage method: This method is applicable if the formation permeability is not too low. However, if the permeability is low, a high-fluid-loss pill is required to reduce propagation of the induced fracture and adequately place the granular materials. After wellbore strengthening, ultralow-fluid-loss mud is required during drilling to reduce the pressure buildup in the fracture section behind the seal.Tip-screening method: This method does not require the squeezing of particles to induce a fracture. Mixing particles with drilling fluid prevents fracture initiation, and if a fracture is induced, this mixture prevents further fracture propagation by tip screening. Tip screening is effective if a lost-circulation zone has some permeability, but is less effective if the lost-circulation zone has no permeability.
The Use of Combined Static- and Dynamic-Material-Balance Methods With Real-Time Surveillance Data in Volumetric Gas Reservoirs
Authors: Ismadi D.. , Kabir C.S.. S. , Hasan A.R.. R.
Published: November 2012

Estimating in-place volume associated with each well, leading to estimation of total reservoir in-place volume, is the cornerstone to any reservoir-management practice. Yet, conventional methods do not always lend themselves to routine applications, particularly when used in singular fashion. However, combining these methods on the same plot has considerable merit in that they converge to the same solution when material-balance (MB) -derived averagereservoir pressure is used in a volumetric system.

This study presents a systematic procedure for estimating the gas-initially-in-place (GIIP) volume when real-time surveillance data of pressure, rate, and temperature are available at the wellhead. Specifically, we show that log-log diagnosis, followed by combined static- and dynamic-MB analysis and transient-productivity-index (PI) analysis, leads to consistent solutions. Thermodynamic behavior of fluids is also explored to ensure that converted pressures at the bottomhole and measured rates have consistency and accuracy for reservoir-engineering calculations.

Layered systems were selected for this study because they represent most situations. Two synthetic cases probed issues pertaining to average-reservoir-pressure computation with the pseudosteady-state (PSS) approach, and two field examples validated the approach presented here.
Casing- and Screen-Failure Analysis in Highly Compacting Sandstone Fields
Authors: Furui K.. , Fuh G.F.. F. , Morita N..
Published: November 2012

Many casing- and screen-damage incidents have been reported in deepwater oil and gas fields in the Gulf of Mexico and other locations around the world. We reviewed historical casing/well failure events in a highly compacting sandstone field and performed a comprehensive geomechanics analysis of various casing-damage mechanisms (tension, axial compression, shear, and bending) related to large reservoir depletion. Among five wells that experienced mechanical well-integrity issues, two of them showed casing restrictions in the caprock at intervals approximately 1,000- to 1,600-ft true vertical depth (TVD) above the top of the depleting (main) reservoir. A multi-finger caliper log obtained from one of the wells indicates that the overburden casing failure occurred at a highly geopressured, thin sand layer approximately 1,100-ft TVD above the top of the compacting reservoir. The remaining casing-failure events occurred near (less than 200-ft TVD) or within the compacting reservoir interval.

A 3D nonlinear finite-element-method (FEM) model has been developed for simulating stress changes in the overburden and the reservoir intervals and evaluating the effect of lithological anomalies on casing stability. The simulation results indicate that large tensile and shear strains could develop within a thin, weak-strength layer in the overburden and at the interface between cap-rock and the depleting reservoir interval. Casing damage by bending/shear could also occur at these thin-layered sands saturated with overpressured gas.

In the reservoir interval, shear stresses acting on the screens can be relatively high because of the difference of the movements between the internal base pipe and the external shroud and gravel. Screen failure may also occur at the welded points. If casing failure occurs in the unperforated sand layer just above the compacting reservoir, it induces localized high-velocity flow on the upper part of the screen, causing potential screen erosion. Casing failure caused by fault slip near the reservoir occurs only if a fault has sealing capability while maintaining a large pressure differential across the fault plane.

The numerical-analysis results presented in this work help engineers understand possible casing- and screen-deformation and -failure mechanisms experienced in highly compacting sandstone fields. On the basis of the study findings, we also present some completion-design guidelines to avoid or mitigate compaction-induced casing damage in both the overburden and reservoir intervals.
An Alternative to Streamlines for Flow Diagnostics on Structured and Unstructured Grids
Authors: Shahvali M.. , Mallison B.. , Wei K.. , Gross H..
Published: November 2012

Streamline-based methods can be used as effective post-processing tools for assessing flow patterns and well allocation factors in reservoir simulation. This type of diagnostic information can be useful for a number of applications, including visualization, model ranking, upscaling validation, and optimization of well placement or injection allocation. In this paper, we investigate finite-volume methods as an alternative to streamlines for obtaining flow diagnostic information. Given a computed flux field, we solve the stationary transport equations for tracer and time of flight by use of either single-point upstream (SPU) weighting or a truly multidimensional upstream (MDU) weighting scheme. We use tracer solutions to partition the reservoir into volumes associated with injector/producer pairs and to calculate fluxes (well allocation factors) associated with each volume. The heterogeneity of the reservoir is assessed with time of flight to construct flow-capacity/storage-capacity (F-vs.-Φ) diagrams that can be used to estimate sweep efficiency. We compare the results of our approach with streamline-based calculations for several numerical examples, and we demonstrate that finite-volume methods are a viable alternative. The primary advantages of finite-volume methods are the applicability to unstructured grids and the ease of implementation for general-purpose simulation formulations. The main disadvantage is numerical diffusion, but we show that a MDU weighting scheme is able to reduce these errors.
Computation of Productivity Index With Capillary Pressure Included and Its Application in Interpreting Production Data From Low-Permeability Oil Reservoirs
Authors: Li Kewen , Chen Zengwei
Published: November 2012

Capillary pressure might be ignored in high-permeability rocks, but it cannot be neglected in low-permeability rocks. To study the effect of capillary pressure on production performance in low-permeability oil wells or reservoirs, the formulas for calculating water cut and dimensionless total and oil productivity indices (PIs) were derived by considering capillary pressure. PI and water-cut data were computed using the new models with capillary pressure included. The results proved that PI increases with water cut in high-permeability rocks but decreases with the increase in water cut within a specific range in low-permeability rocks. Waterflooding experiments were then conducted in core samples with low and high permeabilities. The experimental waterflooding data demonstrated the same relationship between PI and water cut that was proved in the new PI model. Finally, the PI data were calculated using production data from oil wells, and the results were compared with the experimental data of the PI determined from coreflooding tests. The curves of PI vs. water cut, obtained from the production data of oil producers, were consistent with those inferred from waterflooding data in core samples. Note that the core plugs were sampled from the same oil wells. The new PI model was used to explain the difference in production performance between high- and low-permeability oil wells.
An Investigation Into Optimal Solvent Use and the Nature of Vapor/Liquid Interface in Solvent-Aided SAGD Process With a Semianalytical Approach
Authors: Gupta Subodh , Gittins Simon
Published: November 2012

The steam-assisted gravity-drainage (SAGD) process is used widely to recover heavy oil and bitumen from formations in which no other recovery method has proved to be economical. It is an energy-intensive process, and because of economic and environmental reasons, solvents as additives to the injected steam are being explored currently to reduce the energy and emissions intensity of SAGD. The solvent-aided process (SAP), tested in the field and described in the literature, is one such attempt.

In the SAP, a small amount of hydrocarbon solvent is introduced as an additive to the injected steam. Thus, the viscosity of the oil is also reduced because of solvent dilution in addition to heating. The SAP can improve the energy efficiency of SAGD significantly, thus reducing the heat requirement, as shown in field trials discussed elsewhere. However, on the use of the right amount of solvent that can result in best overall performance, there is very little discussion in the literature. Because of the high cost of such solvents, there is incentive to optimize their use in SAGD. Recently, various authors have attempted to address the subject with, for example, arbitrary time-dependent schemes of solvent injections, assessing their impact on results or by treating the internal reservoir dynamics as a black box and using optimization methods, such as genetic algorithms (GAs), to estimate the optimal amount of solvent. While these approaches orient us to the problem in a context-specific manner, it is believed a generalized treatment to estimate optimal use of solvent requires a mechanism-based understanding.

The approach presented in this paper is aimed at estimating the optimal solvent in the context of SAGD. It combines the existing Butler's oil-drainage analytical models (Butler 1985, 1988, 1994) for SAGD and vapor extraction (VAPEX), which deal with heating effect and solvent-dilution effect one at a time, into one. Then, it calculates the time-dependent steam rates to maintain the predicted oil rates in conjuction with solvent rates and, thus, estimates the solvent/steam ratio (SSR) and the steam/oil ratio (SOR). The results are discussed for a few light-alkane solvents. In the process of this exercise, it is discovered that to obtain reasonable SSR and SOR, a significant amount of oil has to drain from a diffuse layer, which has a varying temperature, solvent concentration, and gas saturation (from maximaum gas saturation at the injection end to zero at the vapor/liquid interface).