bluuebunny/crossref_metadata_2025 huggingface dataset:
A Cost Effective Approach to Modeling and Managing Large Gas Fields
Authors: Yee David , Poitevien Ricot
Published: December 2007

Management of gas reservoirs can be a difficult task if there is a varying degree of interference between wells. This difficulty increases with well count and the number of compressors and inter-connected processing plants. Numerical simulation of the integrated network and reservoir can help substantially. However, stability issues in complex networks and extensive data requirements have made simulation costly for large and complex projects.

With an extremely stable and efficient numerical model combined with data preparation techniques that rely on the use of existing databases and automated techniques, as well as streamlined history matching approaches, it has now become economically viable to use integrated models for large shallow gas properties. Without such a model to predict future performance, there is significant risk of over-building and over-drilling for future development. This paper discusses the setup, calibration and day to day use of an integrated model for a shallow gas field in Southern Saskatchewan, Canada.
Drift-Flux Modeling of Multiphase Flow in Wellbores
Authors: Shi H. , Holmes J. A. , Durlofsky L. J. , Aziz K. , Diaz L. R. , Alkaya B. , Oddie G.
Published: December 2007

Drift-flux modeling techniques are commonly used to represent two and three-phase flow in pipes and wellbores. Unlike mechanistic models, drift-flux models are continuous, differentiable and relatively fast to compute, so they are well suited for use in wellbore flow models within reservoir simulators. Drift-flux models require a number of empirical parameters. Most of the parameters used in current simulators were determined from experiments in small diameter (2 inch or less) pipes. These parameters may not be directly applicable to flow in wellbores or surface facilities, however, as the flow mechanisms in small pipes can differ qualitatively from those in large pipes. In order to evaluate and extend current drift-flux models, an extensive experimental program was initiated. The experiments entailed measurement of water-gas, oil-water and oil-water-gas flows in a 15 cm diameter, 11 m long plexiglass pipe at 8 deviations ranging from vertical to slightly downward. In this paper, these experimental data are used to determine drift-flux parameters for steady state two-phase flows of water-gas and oil-water in large-diameter pipes at inclinations ranging from vertical to near-horizontal. The parameters are determined using an optimization technique that minimizes the difference between experimental and model predictions for holdup. It is shown that the optimized parameters provide considerably better agreement with the experimental data than do the existing default parameters.
Probabilistic/Mechanistic Modeling of Slug Length Distribution in a Horizontal Pipeline
Authors: Al-safran E. M. , Sarica C. , Zhang H. Q. , Brill J. P.
Published: December 2007

A Probabilistic/mechanistic modeling was carried out to develop a predictive model for fully developed slug length distribution in horizontal pipeline. Statistical analysis suggested the appropriateness of a Log-Normal model over an Inverse Gaussian model for predicting slug length distribution. A total of 64 data sets were used to empirically correlate the Log-Normal model. Two empirical relationships for mean slug length and slug length standard deviation were developed. A statistical analysis revealed that, in addition to pipe diameter and mixture velocity, volumetric flow rate of the liquid film in the bubble region and the momentum exchange between the slug body and the liquid film are strongly correlated to mean slug length at a 5% significance level. The slug length standard deviation was found to have a significant correlation with film liquid holdup and momentum exchange. A model validation study demonstrated the capability of the probabilistic/mechanistic model to reproduce the experimental data with a satisfactory match. The match was improved when the developed correlations were tuned using the statistical confidence intervals of their coefficients.
Segregated Modeling of Oil-Water Flows
Authors: Shi H. , Jepson W. P. , Rhyne L. D.
Published: December 2007

A four-layer model was developed for horizontal and near horizontal oil-water flows. The four layers consist of pure water, oil-in-water dispersion, water-in-oil dispersion, and pure oil. The two dispersed layers are known to have significantly different viscosities. Therefore, the four-layer model provides a more comprehensive description and better modeling of the phase distribution and velocity profile as compared to earlier modeling efforts using two- and three-layers. Furthermore, the four-layer model uses a more accurate estimate of the mixture layer viscosities as compared to prior work using a simple volumetric averaging approach. The definition of the boundary between the two mixture layers was based on experimental phase-inversion measurements.

This four-layer model is based on experimental work performed on horizontal oil-water flows in a 10-cm diameter and 40-m long pipeline. Flow characteristics including pressure gradient, phase distribution and velocity profile across the pipe, and phase inversion point were measured for an oil and ASTM seawater system. Input water cuts between 0 to 100% were examined at mixture velocities ranging from 0.4 m/s to 3.0 m/s. The system was maintained at 25°C and 0.136 MPa. The model predictions are in good agreement with the experimental data. A multi-layer model is also proposed as the general form of segregated flow model, which can be used for Computational Fluid Dynamics (CFD) modeling efforts. CFD using a preliminary multi-layer model provided reasonable estimates of pressure drop.
A Compendium of Directional Calculations Based on the Minimum Curvature Method
Authors: Sawaryn S. J. , Thorogood J. L.
Published: December 2007

The minimum curvature method has emerged as the accepted industry standard for the calculation of 3D directional surveys. Using this model, the well's trajectory is represented by a series of circular arcs and straight lines. Collections of other points, lines and planes can be used to represent features such as adjacent wells, lease lines, geological targets and faults. The relationships between these objects have simple geometrical interpretations, making them amenable to mathematical treatment. The calculations are now used extensively in 3D imaging and directional collision scans, making them both business and safety critical. However, references for the calculations are incomplete, scattered in the literature and have no systematic mathematical treatment. These features make programming a consistent and reliable set of algorithms more difficult. Increased standardisation is needed.

Investigation shows that iterative schemes have been used where explicit solutions are possible. Explicit calculations are preferred because they confer numerical predictability and stability. Though vector methods were frequently adopted in the early stages of the published derivations, opportunities for simplification were missed because of premature translation to Cartesian coordinates.

This paper contains a compendium of algorithms based on the minimum curvature method (includes co-ordinate reference frames, toolface, interpolation, intersection with a target plane, minimum and maximum TVD in a horizontal section, point closest to a circular arc, survey station to a target position with and without the direction defined, nudges and steering runs). Consistent, vector methods have been used throughout with improvements in mathematical efficiency, stability and predictability of behaviour. The resulting algorithms are also simpler and more cost effective to code and test. This paper describes the practical context in which each of the algorithms is applied and enumerates some key tests that need to be performed.
Engineering Aspects of LWD Quadrupole Measurements and Field Test Results
Authors: Dubinsky V. , Tang X. M. , Bolshakov A. , Patterson D.
Published: December 2007

This paper presents the principle and engineering aspects of an LWD quadrupole shear wave tool. Extensive theoretical study and a series of laboratory and field experiments have been conducted to verify that the quadrupole measurements can determine the true shear velocity of the formation. Experimental results based on the actual laboratory and downhole while drilling measurements are presented in this paper. A multipole (i.e., monopole, dipole, and quadrupole) LWD acoustic tool has been constructed. This tool allows downhole recording of raw and stacked signals acquired by individual receiver elements of the tool. This tool consists of a universal source, which can operate at different frequencies in all three modes, i.e., monopole, dipole, and quadrupole. The six-station receiver array, with four individual receiver elements per station, permits signal acquisition in all these modes. In addition, a triaxial accelerometer system is used to monitor drilling dynamics while drilling.

By making multiple snapshots of the signals in different modes downhole for various drilling conditions, we demonstrate that, when operating in the quadrupole mode, the acoustic signals acquired by the LWD tool possess the true quadrupole characteristics. Comparison of the dipole, monopole, and quadrupole signatures clearly demonstrates how common mode noise is efficiently suppressed in the quadrupole mode. The result shows that even in the case of severe lateral vibrations the combined quadrupole signal provides satisfactory shear wave measurements. The data processing/analysis results are presented. Field-measured quadrupole LWD shear data are evaluated for different drilling scenarios.
LNG: A Proven Stranded Gas Monetization Option
Authors: Coyle David , Durr Charles , Shah Pankaj
Published: December 2007

LNG is a proven gas monetization option that has grown over the past 30 years from a 3 MMTPA industry in the early 1970s to 106 MMTPA industry in 2001. Even so, LNG today accounts for only about 6% of the total natural gas consumed worldwide. The growth in LNG is forecast to remain strong in the coming decade. The ability of the LNG option to continue to compete with existing and emerging gas monetization options will depend on the industry's success in reducing cost throughout the LNG value chain and maintaining exceptional safety, reliability, and environmental performance.

This paper reviews the different components of the LNG value chain from the gas field to the eventual consumer with emphasis on liquefaction plant and regasification terminal. The paper addresses feed gas treatment, liquefaction process technologies, utilities and typical CAPEX for the LNG liquefaction facility. For regasification terminals, the paper will describe off-loading systems, storage tanks, regasification process, vaporizer designs, safety issues and typical CAPEX.

The engineering of LNG liquefaction and regasification facilities is considered a mature technology. However, there are several developments that have or will lead to reduction in life cycle cost of these facilities making LNG a more competitive gas monetization option. These developments include large capacity LNG plants, use of large single shaft gas turbine drivers, all electric drives, and offshore LNG facilities.
Novel Single Trip Horizontal Gravel Pack and Selective Stimulation System Improves Injectivity in Deepwater Wells
Authors: Vilela Alvaro , Calderon Agostinho , Padilha Gesus , Germino Mario
Published: December 2007

Conventional horizontal gravel pack completions typically require multiple trips. Disadvantages of the conventional system may include the loss of rig time due to multiple trips and repeated rig-up / rig-down of pumping equipment, formation damage due to completion fluid losses and fluid loss pills, and incomplete filtercake cleanup across the entire gravel packed interval. A novel single trip horizontal gravel pack and selective stimulation (SHGPSS) system has been developed and implemented. This system allows the gravel pack assembly to be installed, the gravel pack to be pumped, and selective stimulation of the entire packed interval to be performed – all in a single trip. The benefits of the SHGPSS system include valuable rig-time savings and, efficient mechanical diversion of the stimulation fluid.

This paper outlines the first applications of the SHGPSS system to successfully complete five deepwater horizontal injection wells in the Campos Basin, offshore Brazil. Hydrostatic pressure was maintained on the formation during all treatment phases, thus preventing any underbalance that could lift the filtercake off the formation and cause undesirable fluid losses. After gravel packing, a secondary ball was dropped opening a bypass area and converting the gravel pack tool to a selective stimulation tool. The system then provided the ability to perform a filter cake cleanup and stimulation by selectively treating the horizontal interval 40 ft to 80 ft at the time, depending on the screen joint length.

Economic considerations along with completion efficiencies are especially important on deepwater, subsea completions. The novel SHGPSS system can reduce rig-time generating significant cost savings. Exceptional mechanical diversion of the stimulation fluid allows effective filtercake and formation damage removal yielding efficient completions. Case history information on five subsea, offshore Brazil, deepwater wells will further detail the optimized completions accomplished utilizing the SHGPSS technology.
Optimization of Frac/Pack Completions Based on Field Experience
Authors: Morales R. H. , Profinet J. , Piedras J. , Gadiyar B. , Harris S.
Published: December 2007

As the frac/pack technology continues to evolve, there are a number of topics that need more understanding and improvement. Some of these are: The estimation of correct closure pressure, which in turn leads to evaluation of the correct fluid efficiency, and ultimately leads to the design of the slurry schedule. In addition, a proper fluid selection criterion is critical to the placement of highly conductive propped fracture wings via tip screenout.

This paper describes the long strides that have been taken to address these areas. Special attention is given to skin data from build-up tests showing skin increasing with increase in kh. In essence the paper shows effective ways to lower the skin, and consequently increase production. This goal is accomplished by adjusting the design of the frac/pack slurry schedule to observation from field data and to numerical modeling of the fracturing process, and also, by considering the issues stated above. As a consequence, the paper shows that important steps to minimize the skin are to: Design the fracturing fluids to suit the character of the fractures in soft formations where cooldown, fluid velocities, and fluid exposure time are important.Use equilibrium method to fine-tune the closure pressure (and fluid efficiency) evaluation.Clean and pack the perforations not aligned with the fracture.Use diversion techniques to pack the entire reservoir.Evaluate the packing efficiency with bottomhole gauge data (temperature and pressure) and/or radioactive tracers.

When these steps are meticulously followed, fracture performances with lower skins can be obtained as demonstrated in the case history.
Cost-Effective Multidisciplinary Approach to Well Planning and Drilling of a Shallow Water Flow Using Real-Time Monitoring Avoidance in a Gulf of Mexico Deepwater Well
Authors: Citta F. , Russell C. , Greenwood J. A. , Williamson S.
Published: December 2007

This paper will demonstrate the planning steps and benefits realized by an operator through the creation of a multidisciplinary planning team. By evaluating a high-risk zone using their own and third party expertise and the involvement of service company optimization engineers at the planning and drilling phases, significant cost savings were achieved.

Integration of the predrill planning process and offshore real-time monitoring service led to the successful drilling and containment of a shallow water flow (SWF) in the Green Canyon area of the Gulf of Mexico. A detailed shallow geohazards assessment for the proposed exploratory well location was performed. The assessment was based on seismic interpretation of a 2-D, high-resolution hazard survey and on a conventional 3-D seismic data integrated with offset well information.

To improve the likelihood of detecting the SWF during drilling — in addition to Gamma, Resistivity and annular Pressure Whilst Drilling (PWD) measurements — a Logging While Drilling (LWD) acoustic tool capable of deriving acoustic delta t in the larger top-hole section was employed: the first time this had ever been attempted. This employment also allowed the sonic and resistivity normal compaction trend to be established before the onset of any overpressure, a benefit both in SWF detection and for overpressure analysis in deeper sections of the well.

The decision was made to drill 30-in. and 24-in. hole sections with sea water until a SWF was encountered and then use weighted mud to stop the influx as rapidly as possible. A SWF casing and cementing program was implemented once the required section TD was attained.

Transmission of real-time data to wellsite and office locations assisted the entire drilling team to function effectively as a unit and also reduced the response times to critical events.
In Search of an Optimal Parameterization : An Innovative Approach to Reservoir Data Integration
Authors: Schaaf T. , Mezghani M. , Chavent G.
Published: December 2007

History matching, by nature, is an ill-posed inverse problem that can be computationaly intensive and practically infeasible for multi-million cells reservoir models. Therefore, the search of an optimal parameterization is of crucial interest to get a fast history matching procedure. One has to find the number of degrees of freedom of a given problem while avoiding the pitfall of overparameterization. Many techniques (such as singular value decomposition) allow to tackle this problem but the main limitation in reservoir engineering is coming from computational-speed issues.

Using gradient-based optimization techniques, we propose here a complemetary approach which uses the power of adjoint state method to select the degrees of freedom which are significant for the objective function. Data integration may be performed by using the gradual deformation method (GDM) for the geological model parameterization : coefficients of a linear combination of geostatistical realizations are modified as the optimization process goes on. The parameterization is then reduced to the coefficients of the linear combination whatever the size of the geostatistical realizations. Working in a stochastic framework, there is initially an infinity of realizations to choose from. Following the new approach, we are able to compute a priori "refinement indicators" that indicate us which degrees of freedom (i.e. realizations) might improve the iterative reservoir model in a significant way. Using only those useful degrees of freedom, we are able to get a better and faster optimization problem resolution. The use of "refinement indicators" will allow us to reduce to one or even zero the number of randomly picked initial geostatistical realizations.

We applied this methodology to integrate interference test data into 3D geostatistical models (both lognormal and facies-based permeability distributions) containing about two millions cells. This validation highlights the capability of the methodology to speed up the inverse problem resolution by selecting optimal geostatistical realizations from a given set.
Sensitivity Study of Flow Unit Definition by Use of Reservoir Simulation
Authors: Stolz Anne-Kristine , Graves Ramona M.
Published: December 2007

The concept of flow units has been developed to integrate geological and petroleum engineering data. A flow unit is defined as a group of reservoir rocks with similar properties that affect fluid flow.

Different methods can be applied for the definition of flow units and their corresponding petrophysical properties. The amount of information required by each method varies depending on the data and the tools available. This leads to different flow unit interpretation of the same reservoir. The objective of this study is to compare seven methods for flow unit definition to a known answer using numerical simulation to predict the flow performance of the reservoir.

The data set corresponds to the research well CSM Strat Test #61, which is located near Dad, Wyoming, and belongs to the Lewis Shale of the Greater Green River Basin. Conventional and specialized well log information is available for the 1700-ft deep well, in addition to petrophysical measurements on approximately 170 selected core plug samples taken from 600 ft of core. The data for the well includes: gamma ray log, bulk density log, caliper, sonic log, compensated neutron log, nuclear magnetic resonance, air permeability (Klinkenberg-corrected), helium core porosity, minipermeameter readings, capillary pressure analysis, and neural network synthetic permeability.

A simple simulation model is developed using the software ECLIPSE 100, Black Oil. Fluid properties, dimensions of the reservoir, grid size, pressure and production data are the same for all the runs. A waterflood of an oil-water system is simulated as a means of best observing how flow unit delineation affects the results. The results of the reservoir simulation indicate that predicting flow performance varies depending on the flow unit model used. The flow performance is a strong function of the average permeability, and therefore of the flow unit definition method used.

Interpretation of flow units based on petrophysical properties, logs, and stratigraphy are routinely done for characterization of a reservoir. Unless numerical simulation is carried out to confirm the flow unit assignment, errors occur. The use of erroneous flow models leads to incorrect prediction of flow performance in the reservoir.
Subsidence and Horizontal Movement Maps for Application of Reservoir Characterization
Authors: Morita Nobuo
Published: December 2007

Normally, the inverse problem to map reservoir compaction from surface subsidence is an ill-conditioned system since the subsidence bowl gradually changes its curvature, hence, the boundary of pressure depleted area cannot be clearly identified from subsidence bowl. However, the analysis in this paper shows that the peak of lateral surface movement approximately coincides with the pressure depleted peripheral so that if both subsidence and lateral movement maps are constructed, the approximate shape of the pressure depleted area and the lateral distribution of reservoir compaction can be identified. These two maps may be used as it is as a diagnosis tool to identify the location of sealed fault, extent of reservoir section and non-recovered hydrocarbon section.

Imaging the reservoir compaction is further improved if a proper inverse method is applied with the subsidence and surface displacement maps as input data. This paper suggests, for inverse problems with real field conditions where reservoir compaction and elastic moduli are both unknown, to lump multiple layers into a few layers with equivalent anisotropic Young's modulis and to inversely calculate the reservoir compaction and the lumped anisotropic elastic moduli. The resolution and fluctuation of seek parameters are effectively adjusted by the Potter's error covarianace off-diagonal elements. The inverted compaction map shows, more clearly than the original surface displacement maps, the location of sealed fault, extent of reservoir section and non-recovered hydrocarbon section even for relatively deep reservoirs.
Optimal Well Placement in Heterogeneous Reservoirs Via Semi-Analytic Modeling
Authors: Hazlett R. D. , Babu D. K.
Published: December 2007

The need for accurate well productivity models with arbitrary well trajectories spurred a revival in analytic solution methodology for fluid transport problems. Analytic formulations often depict single phase flow throughout the reservoir. The Babu-Odeh horizontal well solution for a box-shaped reservoir with spatially invariant properties is generalized here to allow closed-form solutions for heterogeneous media. A reservoir is decomposed into interacting regions, each with its own reservoir properties and associated analytic potential flow solution. Using well-established boundary element techniques, pressure and flux continuity are imposed at selected interface points to solve for the steady material exchange between regions. Constant pressure and zero flux features (fractures and barriers) are easily entertained at region boundaries. The 2-D, pseudo-steady state solution for heterogeneous media is embedded within a reservoir performance feedback loop of a powerful gradient search method to produce a robust optimal in-fill well placement algorithm. Utilizing this approach, new criteria are developed concerning optimal placement of vertical wells for primary production with respect to heterogeneity, asymmetry, and anisotropy. The semi-analytic method has been extended to 3-dimensional flows to serve as a compute engine for a new generation of reservoir management and optimization tools.
Reservoir Characterization and Infill Drilling Study of a Low-Permeability Carbonate: An Evaluation of Blanket Versus Targeted Infill Drilling Strategies
Authors: Rushing J. A. , Blasingame T. A.
Published: December 2007

This paper presents the methodology and results of a reservoir characterization study of Clear Fork carbonates in the TXL South Unit Field located in Ector County, Texas. The principal objective of our study was to evaluate a targeted infill drilling strategy for future field development. Our study incorporated an integrated approach for which the primary evaluation tool was decline type curve analysis of well production data. The well performance analysis was both supplemented and complemented with petrophysical and geological studies, each representing different reservoir scales. On the basis of our study, we identified areas of the field with the highest reservoir quality and largest oil-in-place volume, thus identifying the areas of the field best suited for infill drilling.
Bringing Al Huwaisah's Volume to Value
Authors: Mijnssen F. C. J. , Davies A. H. , Grondin K. , Keating John , Hsu C. F. , Amthor J.
Published: December 2007

The billion barrel Al Huwaisah Field is located in Northwest Oman and produces from heterogeneous rudist-dominated limestones of the Aptian Shuaiba Formation. It was discovered in 1969 and has been on-stream since 1971. Production peaked at ca. 44,000 bbl/d in 1973 after which production declined to ca. 19,000 bbl/d. Recently, production rates have increased to ca. 28,000 bbl/d, but field-wide recovery factor is still only 18% indicating that potentially large scope volumes remain in the field.

In 2000, an integrated review of the Al Huwaisah field indicated a number of opportunities to mature these large scope volumes. It was noted that key to maturing these opportunities was an improved understanding of the highly complex reservoir architecture, especially regarding the distribution of fractures. Subsequently, a comprehensive fracture study was executed that included both geological information and production data. This study resulted in an improved understanding of the water movements in the field explaining the highly variable first-year net oil rates (0 – 2,500 bbl/d) of the Al Huwaisah wells.

The results of the fracture study were incorporated in newly created static and dynamic models that also took into account the small-scale sedimentological heterogeneities of the Al Huwaisah reef deposits. These models were used together with the historic production review to identify production optimization opportunities, like barefoot completion strategies and water shut-off using expandable tubulars. A few of these opportunities have been implemented so far, resulting in sometimes more than 50 % increase in net oil production for the targeted wells. The barefoot completion strategy has resulted in a 10 % cost saving per well. In addition, well planning using seismic amplitude information was tested, which resulted in more than doubling the initial net production in several wells compared to the average initial well rates in Al Huwaisah.

In identifying the most optimal long-term development strategy for the Al Huwaisah field, the subsurface models are being used to test the benefits of introducing water injection and miscible gas flooding. Based on the model data, a limited water injection field trial is ongoing which resulted in a ca. 20% increase in net oil production for the pilot area. Opportunities for implementing a miscible gas trial are currently being evaluated.
Determination of OGIP for Wells in Pseudosteady-State-Old Techniques, New Approaches
Authors: Ibrahim M. , Wattenbarger Robert A. , Helmy W.
Published: December 2007

In this paper, we investigate the shortcomings of available methods for the analysis of gas well production performance and we propose a new method to more accurately estimate original gas-in-place (OGIP).

Several methods are available in the industry to analyze the production performance of gas wells. The most accurate and dependable of them uses superposition time. This method has the advantage of being able to analyze variable-rate and variable-pressure data, which is usually the nature of field data. However, this method has its shortcomings.

In this paper, we use simulation and field cases to review and compare the application of superposition method and illustrate its shortcomings. We present a new normalized pseudotime plotting function for use in the superposition method to smooth field data and more accurately calculate OGIP. The use of this normalized pseudotime is particularly important in the analysis of highly depleted reservoirs with high compressibility where the superposition errors are largest.

We also present a new tangent method to calculate the OGIP with current reservoir properties for both constant rate and pwf production
Decline Curve Analysis Using Type Curves — Fractured Wells
Authors: Pratikno H. , Rushing J. A. , Blasingame T. A.
Published: December 2007

This work provides the development, validation, and application of new decline type curves for a well with a finite conductivity vertical fracture centered in a bounded, circular reservoir. This work fills a significant void in the modern inventory of decline type curves. In particular, this work is directly applicable to production data analysis for cases taken from low permeability gas reservoirs.

Using an appropriate analytical solution for this case, we prepared "decline" type curves for FcD values from 0.1 to 1000 -individual type curves are generated for each FcD value using a range of reD values from 2 to 1000. The following "type curves" are provided: "Fetkovich" format rate-time decline type curves (constant pressure case): qDd versus tDd"Fetkovich-McCray" format rate-time decline type curves (equivalent constant rate case): qDd versus tDd"Fetkovich-McCray" format rate-cumulative decline type curves: qDd versus NpDd

We provide an example demonstration of the methodology for decline type curve analysis using a field case of continuously measured production rate and surface pressure data obtained from a low permeability gas reservoir.

These solutions/type curves provide an analysis/interpretation mechanism that has not previously been available in the petroleum literature. Compared to field data, we find that the traditional type curve solutions for an infinite conductivity vertical fracture are typically inadequate — and, the new solutions for a well with a finite conductivity vertical fracture clearly show much more representative behavior. This validation suggests that the proposed type curves will have broad utility in the petroleum literature — particularly for applications in low permeability gas reservoirs.
Analytic Wellbore Temperature Model for Transient Gas-Well Testing
Authors: Hasan A. R. , Kabir C. S. , Lin D.
Published: December 2007

Questions arise whether bottomhole pressures (BHP), derived from their wellhead counterpart (WHP), lend themselves for transient analysis. That is because considerable heat exchange may affect the wellbore density profile, thereby making the WHP translation a non-trivial exercise. In other words, gas density is dependent on both spatial locations in the wellbore and time during transient testing. Fully coupled wellbore/reservoir simulators are available to tackle this situation. However, they are not readily adaptable for their numeric formulations.

This paper presents analytic expressions, derived from first principles, for computing time-dependent fluid temperature at any point in the wellbore during both drawdown and buildup testing. The simplicity of the analytic expressions for Tf (z, t) is profound in that one can compute flowing or shut-in BHP's on a spreadsheet.

Two tests were considered to verify the new analytic formulae. In one case, measurements were available at both sandface and surface and partial wellhead information was available in the other. We explored a parametric study to assess whether a given wellbore/reservoir system will lend itself to wellhead measurements for valid transient analysis. Reservoir flow capacity (kh) turned out to be the most influential variable.
Practical Application of Pressure-Rate Deconvolution to Analysis of Real Well Tests
Authors: Levitan Michael M.
Published: December 2007

Pressure-rate deconvolution is a long-standing problem of well test analysis that has been a subject of research by a number of authors. A variety of different deconvolution algorithms have been proposed in the literature. However, none of them is robust enough to be implemented in the commercial well test analysis software. Recently, Schroeter, Hollaender, and Gringarten7, 8 published the deconvolution algorithm that has been shown to work even when reasonable level of noise is present in test pressure and rate data. In our independent evaluation of the algorithm we have found that it works well on consistent sets of pressure and rate data. It fails, however, when used with inconsistent data. Some degree of inconsistency is normally present in real test data.

In this paper, we describe the enhancements of the deconvolution algorithm that allow it to be used reliably with real test data. We demonstrate application of the pressure-rate deconvolution analysis to several real test examples.
Analysis of Interference Tests with Horizontal Wells
Authors: Al-Khamis M. , Ozkan E. , Raghavan R.
Published: December 2007

One of the common assumptions used in horizontal-well interference test analysis is to ignore fluid flow in an out of the horizontal observation well and represent it by an observation point. In some cases, the active well is also approximated by a vertical line source. Using a semi-analytical model, this paper answers three fundamental questions: i) What is the critical distance between the wells to represent the horizontal observation well by an equivalent observation point? ii) Where should the equivalent observation point be placed along the horizontal well? iii) Under what conditions can the active well be approximated by a vertical line source and the exponential integral solution be used for the observation well responses? Two correlations are presented to simplify the analysis of horizontal well interference tests. Example applications are presented and error bounds are documented.
Pressure Transient Derivative Signatures In Presence of Stratiform Super-K Permeability Intervals, Ghawar Arab-D Reservoir
Authors: Gill Harmohan S. , Al-Zayer Rayed
Published: December 2007

This paper describes case studies of observed pressure derivative signatures in the presence of stratiform Super-K permeability intervals in Ghawar field, Arab-D oil reservoir. The case studies (presented in order of increasing complexity) include: 1) an open-hole vertical well intersecting the Super-K interval, 2) a slant horizontal well intersecting the Super-K interval and, 3) a horizontal well at the top of a layered reservoir, not in contact with the Super-K interval and separated from the Super-K interval by low permeability layers.

The stratiform Super-K permeability intervals in Ghawar can be visualized as being like horizontal pancakes of multi-darcy permeability. Since these Super-K intervals are not continuous but rather show up as patches of high permeability, the typical effect on the pressure derivative of a vertical open-hole well is that of a radial composite system.

The most complex derivative signature is observed when a horizontal well is separated from the non-intersecting Super-K interval by low permeability layers. It is very easy to misinterpret this derivative signature without integrating all the available geological and production log data.

The derivative signatures are demonstrated by numerically simulated responses of actual case studies. The importance of identifying these pressure derivative signatures is illustrated in this heterogeneous, multiphase, layered, reservoir where data quality is sometimes poor due to wellbore phase redistribution.
Analytical Solution to the Transient-Flow Problems for a Well Located near a Finite-Conductivity Fault in Composite Reservoirs
Authors: Rahman N. M. Anisur , Miller Michael D. , Mattar Louis
Published: December 2007

This study presents a new analytical solution to the transient flow problem of a well located near a finite-conductivity fault in a two-zone, composite reservoir. The solution accounts for transient flow within the fault, which has been disregarded in all previous studies. The solution is obtained with the Laplace and Fourier transformations, and is verified by comparing a number of its special cases with those available in the literature. A detailed computational procedure is outlined, which is easy to implement in software, and not numerically challenging.
Robust Determination of the Pore Space Morphology in Sedimentary Rocks
Authors: Silin Dmitry B. , Jin Guodong , Patzek Tad W.
Published: December 2007

We present a new robust approach to study the morphology (shapes and connectivity) of the pore space of a sedimentary rock. Our approach is based on the long-established, fundamental concepts of mathematical morphology. In particular, we propose an efficient and stable algorithm which distinguishes between the "pore bodies" and "pore throats," and establishes their respective volumes and connectivity. Our algorithm is extensively tested on the 3D digital images of computer-generated and natural sandstones. The algorithm tests on a pack of equal spheres, for which exact results can be verified visually, confirm its stability. Computer-generated pore space images are used to investigate the impact of image resolution on the algorithm output.

Presently, the proposed algorithm produces a stick-and-ball diagram of the rock pore space. One of distinctive features of our approach is that no image thinning is applied. Instead, the information about the skeleton is stored through the maximal balls associated with each voxel. These maximal balls retain information about the entire pore space. Comparison with the results obtained by a thinning procedure preserving some topological properties of the pore space shows that our method produces more realistic estimates of the number and shapes of pore bodies and pore throats, and the pore coordination numbers.

Based on the information about the maximal ball distribution, we simulate mercury injection and compute a dimensionless drainage capillary pressure curve. We demonstrate that the calculated capillary pressure curve is a robust descriptor of the pore space geometry and, in particular, can be used to determine the quality of computer-based rock reconstruction.
A Physical Model to Explain the First Archie Relationship and Beyond
Authors: Shang Bruce Z. , Hamman Jeffry G. , Caldwell Donald H.
Published: December 2007

We report a new model relating porosity and formation resistivity factor. This model not only explains both Archie and non-Archie behaviors with non-conductive minerals, but also complies with meaningful physical bounds. We define an equivalent rock element aligned with the direction of measurement, in which the pore structure is comprised of two orthogonal components. One is oriented along electrical potential gradient and contributes most efficiently to current flow. The other is perpendicular to the gradient and contributes least efficiently per unit pore volume. The ratio of the former over the latter is defined as "pore structure efficiency". By adjusting pore structure efficiency, any rock can be equivalently represented. Formation resistivity factor can then be expressed as a function of total porosity and pore structure efficiency. Upon analyzing relevant factors in reservoir rocks, we approximate pore structure efficiency as a simple linear or power function of porosity. This leads to a new theoretical relationship between formation resistivity factor and porosity that: explains and agrees with Archie's generalized first equation for a geologically realistic porosity range from 0 to 40%,explains non-Archie phenomena, e.g. noticeable curvature in dual logrithm coordinate space of formation factor versus porosity,is consistent with physical bounds from 0 to 100% porosity, e.g., the magnitude of slope is never smaller than 1, and tends to be 1 as porosity approaches 100%,generalizes multiple porosity domain system into one transitionally smooth description,contains a term representing pore structure efficiency independent of porosity that can be potentially used for fracture analysis,is applicable to both isotropic and anisotropic media by definition.
A Model to Correlate Permeability With Efficient Porosity and Irreducible Water Saturation
Authors: Shang Bruce Z. , Hamman Jeffry G. , Chen Hung-Lung , Caldwell Donald H.
Published: December 2007

This paper introduces a new permeability estimation method using the equivalent rock element model which consists of two pore components, one parallel and the other perpendicular to the potential gradient. Both formation resistivity factor and permeability are related to porosity and pore structure, but permeability also depends on pore scale and internal specific pore area. In water wet rocks, irreducible water saturation is a parameter closely related to pore size or scale and internal specific area. Irreducible water occupies space in both parallel and perpendicular pore components and hinders fluid passage. The relative volume occupied in each component varies with many factors such as pore scale and interconnection, fluid properties, mineralogy and wetting characteristics of the mineral/fluid system. This non-uniform occupancy is approximated by a simple power function. An efficient flow porosity is defined by modifying efficient electrical porosity using irreducible water saturation to account for scale and specific pore area. The correlation between efficient flow porosity and permeability is much greater than those in many of the commonly used methods. This method has been applied to several sets of cores from different parts of the world. Better correlations between measured and estimated permeability have been obtained in all datasets compared with other published approaches, such as porosity versus logarithm of permeability, Kozeny-Carman, Wyllie-Rose, and Timur methods.
The Results of Increased Fracture Conductivity on Well Performance in a Mature East Texas Gas Field
Authors: Flowers J. R. , Hupp M. T. , Ryan J. D.
Published: December 2007

In our industry's never-ending search to cut cost, there has been an alarming trend in the design of hydraulic fractures. This trend is the shift to lower fracture conductivity, which is being achieved through reduced proppant concentrations and the selection of less expensive, inferior proppants. This change is most evident in tight gas completions where even very low fracture conductivities are assumed to achieve infinite-acting fractures. Obviously, these changes can reduce the overall cost of the fracture treatment, but at what cost to well performance? This paper will review the production and economic impact of altering fracture conductivity in 18 low permeability wells in a mature East Texas gas field.

Most traditional conductivity calculations are problematic because they are based on laboratory-generated numbers and ignore the effects of non-Darcy and multi-phase flow. While most frac design engineers routinely and correctly include 50% damage introduced to the proppant pack by polymers, they continue to dismiss the additional 90% conductivity reductions that can be induced by non-Darcy and multi-phase flow. This leads to a drastic underestimation of the pressure drop within the proppant pack, and consequently, production results that fail to meet expectations.

The purpose of this paper is to demonstrate that these rate-induced conductivity reductions are real and that production improvements can be achieved through increased conductivity, although conventional "Darcy" analysis may erroneously indicate otherwise. In this case study, production results from eighteen wells located in a mature gas field in East Texas will be presented. Nine wells were completed with designs based on traditional Darcy flow models and nine offset wells utilized a new design to incorporate non-Darcy and multi-phase flow effects. In addition to production results, economic analyses are provided to show that the increased job cost is quickly recovered with improved production. Estimated ultimate recovery for each well is presented in an attempt to quantify the long term effects of increased conductivity. These analyses demonstrate that reducing fracture conductivity, as a cost savings measure, can significantly reduce both cash flow and net present value of the well. Production results to date indicate that the wells receiving the higher conductivity fractures will produce an average of 2 BCF/well incremental reserves for an additional investment of less than $50,000/well.
Avoiding Proppant Flowback in Tight-Gas Completions with Improved Fracture Design
Authors: Canon Javier M. , Romero Diego J. , Pham Tai T. , Valko Peter P.
Published: December 2007

In this paper we describe the possibility and benefits of incorporating the stability analysis of the proppant pack during the design stage of hydraulic fracturing treatments.

After the well is treated and cleaned up, the flowback of proppant from a fracture-treated formation is highly undesirable for several reasons, including possible damage to the wellhead and flowlines, operational complications, and last but not least, decrease in well-productivity. The issue has been studied on an empirical basis and the most important factors have been determined. Nevertheless, qualitative models suggested so far seem to work only under limited conditions and currently there is no clear methodology for predicting the occurrence of proppant flowback while designing the treatment.

In this work we review previously suggested prediction methods and analyze the proppant flowback patterns experienced in 24 South-Texas tight-gas completions. As a result of the study we conclude that the predictive power of the available models is not satisfactory and the implications for "proppant stability control agents" are not based on convincing evidence. A new semi-mechanistic model is proposed that shows reasonable agreement with both laboratory and field data. A methodology is suggested to incorporate the proppant flowback prediction at the fracture design stage. The suggested methodology is based on the concept of "minimum necessary departure from optimality to satisfy technical constraints", in this case the constraint being to keep the likelihood of proppant flowback under a certain threshold.