bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

SummaryAn 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

Summary
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

Summary
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

Summary
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

Summary
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

Summary
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

SummaryThe 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

Summary
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

Summary
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

Summary
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.