bluuebunny/crossref_metadata_2025_split huggingface dataset:
Capillarity Controlled Displacements in Sediments With Movable Grains: Implications for Growth of Methane Hydrates
Authors: Prodanovic Maša , Bryant Steven L. 
Published: September 2008

Abstract
Gas invasion of sediments is one mechanism by which methane hydrates are believed to form. As the capillary pressure exerted by an accumulated gas phase below the hydrate stability zone increases, it can exceed the entry pressure of the sediment within the hydrate stability zone, leading to a drainage displacement. Alternatively it can exceed the parting pressure of the sediment, leading to a gas-filled fracture propagating into the sediment. In unconsolidated ocean sediments, the capillary pressure may also be large enough to move grains apart during drainage. This motion alters the pore throat sizes which control subsequent drainage of the sediment. A model for the dynamics of this process is useful for assessing the competition between drainage (controlled by capillary forces) and fracturing (controlled by pore pressure and earth stresses). This in turn provides insight into the possible growth habits within the hydrate stability zone.
To model this process we consider immiscible displacements when fluid/fluid interfaces are controlled by capillary forces. The progressive quasistatic (PQS) algorithm based on the level set method readily determines the pore level geometry of these interfaces. Capillary pressure generally exerts a net force on grains supporting an interface. We extend PQS algorithm to implement a kinematic model of grain displacement in response to that force. We examine the changes in the drainage curve caused by this coupling. We compute the interfacial area associated with the bulk water phase, anticipating preferential growth of methane hydrate there.
When grains can move in response to net force exerted by the gas phase, small variations in an otherwise uniform distribution of pore throat sizes lead to self-reinforcing, focused channels of gas phase. In contrast to behavior in stationary grains, the drainage curve exhibits no clear percolation threshold. Displacements in materials with broad throat size distributions also exhibit self-reinforcing channels. Behind the leading edge of the displacement front, the net force exerted on the grains tends to push them together. This effectively seals off these regions from subsequent invasion. Thus hydrate growth tends to be localized along the channel of displaced grains.
Identifying Inefficient Drilling Conditions Using Drilling-Specific Energy
Authors: Armenta Miguel 
Published: September 2008

Abstract
A novel correlation identifying inefficient drilling conditions is presented using experimental and field data. Historically, Mechanical Specific Energy (MSE) has been used to improve the drilling performance with mixed results. Drilling Specific Energy (DSE) is the amount of energy required to destroy and remove underneath the bit a unit volume of rock. DSE includes axial, torsional and hydraulic energy. DSE is different than MSE because it includes a hydraulic term. The initial MSE correlation (Teale, 1964) has been modified to accommodate the new hydraulic term.
Experimental and field data presented on the paper show that DSE can be used to identify inefficient drilling conditions. Experimental results illuminate the importance of including bit hydraulics into the specific energy analysis for drilling optimization. Field results reveal specific patterns for inefficient drilling conditions such as; bit balling and friction limited wells. These field results also enligthen a good correlation between the calculated DSE and the rock compressive strength.
The novel correlation presented in this paper will help to improve the drilling efficiency worldwide. The new hydraulic term included on the specific energy correlation is the key to correctly matching the amount of energy used to drill and the rock compressive strength. Also, this new term illuminates how much hydraulic energy is needed to drill faster and efficiently when the mechanical energy (axial and torsional) is increased.
Sand or Mud Removal in Low Bottom Hole Pressure Wellbores Using Jet Pump and Concentric Coiled Tubing Leads to Improved Production
Authors: Li J. , Crabtree A. , Kutchel M. , Diaz J. , Reyes W. , Dugarte R. , Peña L. 
Published: September 2008

Abstract
Horizontal drilling and completion are common practice for accessing conventional and heavy oil reservoirs. During the drilling process, the formation pore pressure is less than the drilling fluid's hydrostatic pressure. This can lead to some fluid loss before a filter cake is formed to prevent further mud losses. For unconsolidated formations, it is prefer to keep the filter cake in the place to maintain the hole's integrity during the well completion period while running the liner. However, the filter cake can be broken down by the sliding and rotating of the bottom hole assembly. These breakdowns can lead to high completion fluid losses to the formation. Sand production is also a common problem associated with unconsolidated formations. These drilling & completion practices, sand production, have resulted in a demand for well intervention that can economically remove mud damage and produced fill throughout the whole length of horizontal wells.
Since 1995, a technology combining concentric coiled tubing (CCT) with a jet pump has been developed and used to remove both the drilling fluids, filter cake and solids. Initially it was developed for horizontal heavy oil reservoirs where pressures are low and oil viscosity is high, without placing hydrostatic loads on the reservoir. The job data from more than 600 sand/well vacuuming operations worldwide has been compiled into a database.
This paper reviews the well information and the key operating parameters: maximum depth, bottom hole pressure gradient and pump rate. The engineering challenges, best practices and lessons learned from the sand/well vacuuming process are also summarized. Analysis of this data yields a better understanding about the vacuuming technology and provides good guideline for future operations.
Case histories are provided demonstrating how to deploy the different sand/well vacuuming bottom hole assemblies (BHA) for different applications. Post job analysis indicates CCT vacuuming technology reduces the skin damage and increases the production compared to non-vacuumed wells. Moreover, the details estimated from sand and other fluid influx profiles along the wellbore during the vacuuming process, are used to evaluate well production and develop a management strategy.
From Mega-Cell to Giga-Cell Reservoir Simulation
Authors: Dogru Ali H. , Fung Larry S. K. , Al-Shaalan Tareq M. , Middya Usuf , Pita Jorge A. 
Published: September 2008

Abstract
For many oil & gas reservoirs, especially large reservoirs in the Middle East, the availability of vast amounts of seismic, geologic and dynamic reservoir data result in high resolution geological models. Because of the limitations of conventional reservoir simulator technologies, high resolution models are upscaled to flow simulation models by reducing the total number of cells from millions to a few hundred thousand. Flow simulators using upscaled reservoir properties produce average reservoir performance and often fall short of accurately predicting recovery.
Realizing the limitations of the conventional simulators for the giant oil and gas reservoirs, parallel reservoir simulators have been developed. The first generation of parallel simulators increased the simulator capabilities by an order of magnitude — the result was that mega (million) cell simulation became a reality. Parallel computers, including PC Clusters, were successfully used to simulate large reservoirs with long production histories, using millions of cells. Mega-cell simulation helped recover additional oil and gas due to better understanding of reservoir heterogeneity. The speed of parallel hardware also helped, making many runs to address uncertainty possible.
Despite the many benefits of parallel simulation technology for large reservoirs, the average cell size still remains in the order of hundreds of meters (m) for large reservoirs. To fully utilize the seismic data, smaller grid blocks of fifty m in length are required. This size of grid block results in billion (Giga) cell models for giant reservoirs. This is a two orders of magnitude increase from the mega-cell simulation. To simulate Giga-cell models in practical time, new innovations in the main components of the simulator, such as linear equation solvers, are essential. Also, the next generation pre- and post-processing tools are needed to build and analyze Giga-cell models in practical times.
This paper describes the evolution of reservoir simulator technology, from Mega-Cell scale to a Giga-Cell scale, presenting current achievements, challenges and the road map for Giga-Cell Simulators.
Application of the Efficient Frontier Concept to Resource Play Budget Evaluation and Portfolio Optimization
Authors: Tonnsen Robert R. 
Published: September 2008

AbstractThe oil and gas industry contains significant inherent risks that greatly affect a company's ability to achieve predicted performance. In an attempt to better manage risk and uncertainty during the decision making process, the efficient frontier concept has been proposed as a method for portfolio optimization. This paper analyzes the application of the efficient frontier concept to a yearly budget allocation process considering unconventional resource play opportunities. Economic and optimization models were developed with assumptions specific to resource plays. The models show that the expected risk, uncertainty, and return on investment change according to the level of investment, project selection, the number of planned wells, and to the grouping of wells for budgeting purposes. The budget dependency of the risk and return cause an oddly shaped efficient frontier resulting in mean-variance efficient portfolios that may not be optimal when based on a set level of risk. In addition, the results show that conventional rank and cut methods for portfolio selection may suffice for resource play budget allocation. However, even though the efficient frontier does not often offer definitive solutions for portfolio optimization, illustrating the interactions among portfolio properties and providing insight into inefficient budget allocations could make the efficient frontier optimization process invaluable.
Sand Quantification: The Impact on Sandface Completion Selection and Design, Facilities Design and Risk Evaluation
Authors: Addis M. A. , Gunningham M. C. , Brassart Ph. , Webers J. , Subhi H. , Hother J. A. 
Published: September 2008

Abstract
Sand Quantification involves predicting the volumes of sand which can be produced at the sandface completion and transported to the surface facilities for different operational scenarios. Sand quantification estimation is still novel in the industry, and this paper describes its application in completion selection and design, facilities design and operation, and facilities risk evaluation, with reference to a high rate gas field development.
The estimation of sand production volumes for openhole and cased and perforated completions is presented for the high rate gas wells, along with the workflow used for the selection and optimisation of the completion design, based on these estimates. The optimum completion aims to delay the onset of sand to surface for the first 18 years of production, whilst maintaining high gas productivity (&gt;300mmscf/d/well). The selection of contingency sandface completions is also discussed along with mitigation measures in the event of unexpected sand production. The impact of the sand quantification on surface facilities design is discussed based on a probabilistic approach, along with the operational procedures identified to manage this sand.
The operational evaluation is based on a Quantitative Risk Analysis (QRA) of the facilities and wells, which helped identify operational changes to further reduce the ‘as built’ low risk operation. This use of sand quantification for completion design and for QRA of facilities forms a new capability and an extension to the existing use of sand prediction technologies.
Development of a Response Surface Based Model for Minimum Miscibility Pressure (MMP) Correlation of CO2 Flooding
Authors: Ghomian Yousef , Pope Gary A. , Sepehrnoori Kamy 
Published: September 2008

Abstract
Correlations are commonly used to predict CO2 multiple contact miscibility (MMP) since such correlations are generally inexpensive and easy to use. In this study, we used a novel approach based upon four dimensionless scaling groups commonly used for hydrocarbon phase behavior modeling (reduced temperature and acentric factors for light and heavy pseudo components) as well as multivariate regression analysis based on response surface methodology to develop an MMP correlation for a broad range of reservoir oils. Applying the response surface method and multivariate regression analysis made it possible to quantify and rank the effect of each one of the mentioned dimensionless groups on the predicted MMP value. Since reservoir temperature is one of the main parameters, slim tube simulations were performed at four different reservoir temperatures (90, 150, 180, and 220 °F) for all of the fluid models. Based on the results from these simulations, and by performing multi-variate regression analysis, MMP values were correlated using a response surface based on linear, quadratic, and third degree equations. Our new MMP correlation takes into account the important equation-of-state properties for heavy- and light-oil components as well as temperature. Predicted MMP values from the new correlation were compared with previously published MMP correlations and found to have a lower average error.
Pressure Transient Analysis in Partially Penetrating Infinite Conductivity Hydraulic Fractures in Naturally Fractured Reservoirs
Authors: Igbokoyi Alpheus O. , Tiab D. 
Published: September 2008

Abstract
Although the effect of partial penetration of an infinite conductivity hydraulic fracture has been considered in a homogeneous reservoir, there is no study in similar problem in naturally fractured reservoirs. This paper presents the analysis of the solution to such problem in naturally fractured reservoirs. The method of analysis with or without type curve that enables us to evaluate the permeability in the three principal axes directions is also presented.
The solution to the mathematical model was obtained in Laplace domain with elliptical flow model. Several type curves were generated to study the pressure behavior. Both the early linear and pseudo-radial flow regimes are observed. The duration of the early linear flow regime is a function of the natural fractures storativity ratio, interporosity flow coefficient and the dimensionless hydraulic fracture's height. The effect of the dimensionless hydraulic fracture's height on the duration of the linear flow becomes negligible as its dimensionless height approaches unity. Therefore there is no single unique value of a dimensionless time for the end of the linear flow regime as in the case of homogeneous reservoir. Raghavan et al (1978) determined the end of the linear flow regime in fully penetrating hydraulic fractures in homogeneous reservoir to be 0.016. This value is based on the dimensionless pressure drop only. In this study, this value was found to be 0.01 and it was evaluated with pressure derivative curve which is more accurate.
Two simulated examples were used to validate the method of the analysis developed. The results obtained are in agreement with the input data.
Analyzing Buildup Data Following a Highly Unstable Rate History
Authors: Larsen Leif 
Published: September 2008

Abstract
This paper addresses practical aspects of analyzing buildup data following a highly unstable rate history, such as cases where the rate decreases or increases significantly prior to shut-in, or even drops to zero (well dies) "prior" to a normal shut-in. Although any rate history can be approximated with a piecewise constant rate history, it turns out that a piecewise linear rate history with a modified superposition expression more readily can be used to recognize standard flow regimes and to determine formation flow properties when the rate prior to shut-in varies sharply with time. The simplest cases considered are based on a single flow period with the rate changing linearly from a low to a high value or from a high to a low value prior to shut-in, including cases starting or ending at zero. For such cases it is easy to overlook a simple flow model if single-rate analyses are attempted with an average rate or some other expected representative rate value.
With piecewise linear rate histories it is possible to accurately represent piecewise monotonic rate changes with just a fraction of the number of rate changes needed with a piecewise constant history. Meunier et al.1 took advantage of this in a paper dealing with analyses of afterflow data. The present paper extends this approach to arbitrary cases with rapidly increasing or decreasing rates prior to shut-in or scattered throughout a test sequence. To do this in routine analyses the method must be included in standard software packages for well test analysis. For direct matches of data and models this requires integration to replace simple difference expressions, but this can be handled automatically by the software without user input. Without the software option the results can at least be implemented in spreadsheet applications for test designs and analyses if necessary basic solutions for radial flow with storage and skin, or more complicated models, are available. For specific flow regimes (radial flow, linear flow, etc.), this can be handled with closed-form expressions without numerical integration routines.
Only synthetic cases have been included to illustrate the characteristics of buildup data influenced by changing rate prior to shut-in. The synthetic cases are all of the simplest type, with just one flow period prior to shut-in. Theoretical results about more complex cases are presented, but to illustrate the characteristics of buildup data following unstable flow, it was concluded that the simplest cases were best suited to this end. Results are presented both for simple semilog data sets and for data generated from a model with wellbore storage and a single fault added to increase the complexity of data.
Real-Time Data Enables Real-Time Decision Making in Well Intervention Operations
Authors: Huval Sidney , McNicol Jim 
Published: September 2008

Abstract
Modern well intervention operations bring with them serious risk of non-productive time (NPT) and cost escalation through the customary practice of working "blind" – that is, by relying solely on surface measurements such as RPM, hook weight and rotary torque to manipulate well intervention tools tens of thousands of feet downhole. Often the true results of these manipulations are not known until the bottomhole assembly (BHA) has been retrieved to surface, and then further trips become necessary to complete a satisfactory intervention operation. Until now, there has been no accurate or consistent method for observing the forces and conditions experienced in the downhole intervention environment.
A new system has been developed to present quantified parametric downhole tool force and environment information to the operator at surface in real time and thus enable on-the-spot decision making for the optimization of well intervention operations. The system integrates a sensor sub and a basic measurement while drilling (MWD) tool into the intervention BHA. Standard mud pulse technology transmits signals to surface for decoding and visualization by an independent stand-alone unit.
A significant number of successful operations have been conducted during system integration testing, and the first commercial jobs have just been completed. This paper will demonstrate the benefits of real-time data enabling real-time decision-making in challenging well intervention scenarios, and through case history data, elucidate new refinements in the system architecture.
Efficient Region Decomposition for Parallel Simulation Accounting for Uncertainty in the Reservoir Model
Authors: Kim Yonghwee , Srinivasan Sanjay , Bryant Steven L. 
Published: September 2008

Abstract
Reservoir region delineation is essential for parallel flow simulation of large reservoir models. We argue that the delineation of least correlated, most sensitive regions mitigates the requirements for load-balancing and flux-matching that are the bane of current parallel simulation procedures. The optimal choice of sub-regions satisfies two conditions. First, the values of permeability in the sub-regions should have the greatest influence on the performance of injection and/or production wells. Second, the sub-regions should exhibit the least possible correlation with one another. Principal component analysis (PCA) of sensitivity matrices readily identifies regions meeting both the conditions. There are two methods for obtaining sensitivity matrices: i) the Hessian matrix calculated internally by a flow simulator, and ii) a covariance matrix calculated using a suite of realizations. The latter method is more robust and effective in terms of fluid flow connectivity, computational cost, availability to implement and capability of capturing uncertainty of reservoir models. In this paper, we focus on domain delineation using the covariance matrix and apply the method to a series of examples. We discuss key advantages of this method over the alternative of using the Hessian matrix.
A Decade of Experience—The Water-Based Thermal Insulating Packer Fluid
Authors: Javora Paul H. , Pearcy Rick , Wang Xiaolan , Stevens Dick , Qu Qi 
Published: September 2008

Abstract
The concept of ‘flow assurance’ has numerous connotations, especially when it comes to deepwater operations. Just a decade ago as deepwater came into vogue, flow assurance terminology would primarily refer to chemical injection technology. This quickly changed however, as demand for effective thermal insulation techniques to prevent annular pressure buildup, costly wax and asphaltene deposition, and gas hydrate formation escalated. Concurrently, effective water-based insulating fluids were introduced into the field, and were quickly accepted as a valuable method to retain heat in produced fluids and prevent heat loss to external annuli and surrounding environments. To date, over 70 installations of water-based insulating fluids have been completed, with applications ranging from controlling annular pressure buildup, to controlling heat loss in one or more riser annuli.
This paper presents case histories from the originally designed insulation requirements in casing to control annular pressure buildup, to new evolutions applicable in modern risers. Operational details of installations completed, successful removal of the insulating fluid from wells, and successful re-use of the removed insulating fluids are presented. Results from an unexpected long-term shut-in, and field data connecting the effectiveness of water-based insulating fluids to model predictions are also presented.