bluuebunny/crossref_metadata_2025 huggingface dataset:
The Impact of Constitutive Laws on Wellbore Stability: A General Review
Authors: Charlez P. A.
Published: December 2007

This paper is focused on soft deep rocks that can induce strong well-bore-stability problems. In the first part, it is shown that these rocks generally exhibit plastic-type behaviors. In the second part two elasto-plastic models (Cam-Clay and Laderock) are briefly presented. In the third part, these constitutive laws are applied to wellbore stability through analytical solutions or finite element codes. Finally, in the fourth part, a case history is discussed in detail. We insist on the difficulty to properly define the boundary conditions of the problem (in-situ stresses and virgin pore pressure) and on the subjectivity of the criterion translating the boundary wellbore problem in stability recommendations. Some keys for future research are proposed.
Abnormally High Fluid Pressures and Associated Porosities and Stress Regimes in Sedimentary Basins
Authors: Yassir N. A. , Bell J. S.
Published: December 2007

The relationships between overpressures and porosity and overpressures and stress regime are found to differ significantly according to the geological setting and overpressure generating mechanism. These factors must be taken into account in pore pressure prediction techniques and in correlations between pore pressure and minimum horizontal stress. Two examples from overpressured Canadian basins are presented to illustrate the above.
Hole-Cleaning Capabilities of an Ester-Based Drilling Fluid System
Authors: Kenny Patrick , Hemphill Terry
Published: December 2007

Well 33/9-C02, located in the Statfjord field in the Norwegian sector of the North Sea, held the world record in extended-reach drilling from 1993-95. To successfully drill a well of this type, an efficient drilling fluid is required to suspend the weighting material and provide good carrying capacity. The ester-based mud system used in the 12¼ and 8½-in. hole sections of this well exhibited excellent holecleaning capabilities. This paper describes the fluid's performance in the field and in the laboratory where the fluid was tested under downhole conditions. Fluid rheological behavior is described with the more accurate yield-power law (YPL) (Herschel-Bulkley) model.
Passive Imaging of Hydrofractures in the South Belridge Diatomite
Authors: Ilderton D. C. , Patzek T. W. , Rector J. W. , Vinegar H. J.
Published: December 2007

We present the results of a seismic analysis of two hydrofractures spanning the entire diatomite column (1110-1910 ft or 338-582 m) in Shell's Phase II steamdrive pilot in South Belridge, California. These hydrofractures were induced at two depths (1110-1460 and 1560-1910 ft) and imaged passively using the seismic energy released during fracturing. The arrivals of shear waves from the cracking rock ("microseismic events") were recorded at a 1 ms sampling rate by 56 geophones in three remote observation wells, resulting in 10GB of raw data. These arrival times were then inverted for the event locations, from which the hydrofracture geometry was inferred. A five-dimensional conjugate-gradient algorithm with a depth-dependent, but otherwise constant shear wave velocity model (CVM) was developed for the inversions. To validate CVM, we created a layered shear wave velocity model of the formation and used it to calculate synthetic arrival times from known locations chosen at various depths along the estimated fracture plane. These arrival times were then inverted with CVM and the calculated locations compared with the known ones, quantifying the systematic error associated with the assumption of constant shear wave velocity. We also performed Monte Carlo sensitivity analyses on the synthetic arrival times to account for all other random errors that exist in field data. After determining the limitations of the inversion algorithm, we hand-picked the shear wave arrival times for both hydrofractures and inverted them with CVM. Finally, to correct for the areal inhomogeneity of the rock, we calculated the distortion of conical waves that were generated by air gun blasts in a remote observation well. This novel technique improved significantly the accuracy of the event locations in the shallow hydrofracture. The azimuth of both hydrofractures was N21° ±4°E. In each treatment well, there were two separate hydrofractures at two different depths that correspond to the diatomite layers with higher permeabilities. Both shallow hydrofractures were asymmetrical. Initially, the upper NE wing was 230 ft long, whereas the lower SW wing was only 30 ft long. The deep hydrofracture was symmetrical and the wings of its two parts were initially 130 and 10 ft long, respectively. These conclusions agree well with temperature surveys in the surrounding observation wells during steam injection.
Vertical Multiphase Flow Correlations for High Production Rates and Large Tubulars
Authors: Aggour M. A. , Al-Yousef H. Y. , Al-Muraikhi A. J.
Published: December 2007

Numerous correlations exist for predicting pressure drop in vertical multiphase flow. These correlations, however, were all developed and tested under limited operating conditions that do not match the high production rates and large tubulars normally found in the Middle East fields. This paper presents a comprehensive evaluation of existing correlations and modifications of some correlations to determine and recommend the best correlation or correlations for various field conditions. More than 400 field data sets covering tubing sizes from 2⅜ to 7 in., oil rates up to 23,200 B/D, water cuts up to 95%, and gas/oil ratio (GOR) up to 927 scf/STB were used in this study. Considering all data combined, the Beggs and Brill correlation provided the best pressure predictions. However, the Hagedorn and Brown correlation was better for water cuts above 80%, while the Hasan and Kabir model was better for total liquid rates above 20,000 B/D. The Aziz correlation was significantly improved when the Orkiszewski flow-pattern transition criteria were used.
A Model for Predicting Injectivity Decline in Water-Injection Wells
Authors: Pang Shutong , Sharma M. M.
Published: December 2007

We propose a new method to predict the injectivity decline for water-injection wells. Both internal and external filtration are considered in this method. A transition time from internal to external filtration is calculated by use of the trapping efficiency obtained from Stokesian dynamics simulations. The radius and the permeability of the damage zone are calculated by use of a deep-bed filtration model. Equations are derived that allow us to combine the flow resistance in the external and internal filter cakes to obtain the overall decline in injectivity.
A Modern Gunbarrel of Unique Design
Authors: Powers M. L.
Published: December 2007

Although regarded by many as obsolete, gunbarrels (or wash-tanks) are still used for primary oil treating in many areas. This paper describes a modern gunbarrel constructed from an existing 5,000-bbl tank. Oil treating without the addition of heat was feasible because of the combination of relatively warm produced fluid and lenient basic sediment and water (BS&W) limits. The subject vessel provides gas separation and contains two spreaders that were designed to provide good oil- and water-phase retention and to facilitate solids separation and removal. The oil-phase spreader has a diameter equal to 78% of that of the vessel. It incorporates a unique deep skirt, having a pattern of restrictive exit ports that imposes uniform radial oil-phase flow over a wide range of rates and is relatively insensitive to minor misleveling, which is not the case for common serrated-skirt spreaders. The design of the unique vessel internals permitted assembly without welding at the battery site. Differences in the contribution of the water-bath zone of heated and nonheated gunbarrels are discussed, and it is shown that nonheated-vessel designs that increase water-phase residence time and facilitate convection in the water-bath are the most effective, a result of conservation of intrinsic well-stream heat. It is also demonstrated that the optimum oil-blanket thickness is a compromise between oil-residence time and oil temperature in nonheated vessels that capture water-phase heat. Vessel internals that entrap oil beneath water (such as the oil-phase spreader of the subject vessel) are subjected to a buoyant force in addition to the weight of water displaced by steel. This effect is discussed, and design equations are developed to calculate the net buoyant force exerted upon a specific spreader and the gauge steel from which a spreader must be constructed to preclude floating. An example is included that illustrates the application of these equations to the subject vessel.
Wettability and Relative Permeability of Prudhoe Bay: A Case Study in Mixed-Wet Reservoirs
Authors: Jerauld G. R. , Rathmell J. J.
Published: December 2007

This paper describes the variation in wettability and relative permeability at Prudhoe Bay. We show that measurements are consistent with recent theories of the relationship between water-saturation, pH, wettability and relative permeability.1 In particular, the wettability of the reservoir changes from water-wet low on structure near the water/oil contact to mixed-wet behavior higher on structure. Increasing oil-wetting character is correlated to decreasing water saturation. Changes in wettability are also accompanied by changes in water-flood recovery efficiency and are optimum at Amott indices approaching zero. Lithology also impacts recovery efficiency, with more clay-rich rocks having higher residual oil saturations.
The Scaleup of Two-Phase Flow in Porous Media Using Phase Permeability Tensors
Authors: Pickup Gillian E. , Sorbie Kenneth S.
Published: December 2007

The effects of different levels of geological heterogeneity on a fluid displacement process may be captured at a larger scale using scaleup techniques. In the context of reservoir simulation, these are algorithms which should reproduce the results of fine grid calculations on a coarser grid. These techniques are referred to as pseudo-isation, the main objective being to produce pseudo-functions which can be used on the coarse grid. When carried out successfully, the pseudo-functions (e.g. pseudo relative permeabilities) incorporate the interaction between the fluid mechanics and the heterogeneity as well as correcting for numerical dispersion. These pseudo-functions also depend on the viscous/capillary and viscous/gravity ratios and are valid for the boundary conditions relevant to the particular flows.

For single phase flow, the scaleup problem involves the derivation of effective permeability which, in general, is a tensor quantity. Multi-phase flow is more complex since scaled-up dynamic transport quantities must be calculated which depend on phase saturation, flow rate etc. In this paper, we present a method which extends the idea of tensor (absolute) permeability to tensor effective phase permeabilities. They are extensions of conventional functions which also include the off-diagonal phase crossflow terms which may be important in certain systems. Two phase tensor methods are presented which are valid (a) in the capillary equilibrium limit and (b) for arbitrary values of viscous/capillary and viscous/gravity ratios. Numerical examples of the application of these methods are presented for ripple-bedded systems where the two phase crossflow effects are significant, and where oil trapping within the lamina structure may occur under certain conditions. The results show that it is important to use phase tensors in upscaling where gravity effects are significant, in order to generate the correct vertical flows.
Application of Oil-Based-Mud Pressure Coring to the Determination of In-Situ Water Saturations
Authors: Charlson G. S. , DeRuiter R. A. , Spence A. P. , Warner H. R.
Published: December 2007

This paper describes a field project which applied pressure coring using oil-based mud (OBM) to determine whether a surfacing correction was needed to use OBM-core water saturations (SW) as accurate values for in-situ Sw. Six OBM pressure cores were cut in two Prudhoe Bay field wells, one in the low Sw area and the other in the higher SW area. This paper discusses the equipment and procedural changes, both in the field and in the laboratory, required for this project.

Pressure cores were taken from two geologically different intervals: the Sag River sandstone and the Ivishak (Sadlerochit) sandstone. The results of this project are that for the Ivishak sandstone, no water was expelled during the thawing (taken to be equivalent to core depressuring) for the full range of Sw (1 to 45%); but for the Sag River sandstone, some water was expelled for samples with Sw values of 25 to 40%. The difference in water-expulsion results is attributed to differences in pore structure. Finally, the application of these results to the calculation of in-situ Sw is discussed.
Microbial Profile Modification With Spores
Authors: Bae J. H. , Chambers K. T. , Lee H. O.
Published: December 2007

To overcome the shortcomings of conventional, near-wellbore profile modification methods, a microbial profile modification (MPM) method with spores was investigated. A halotolerant, spore-forming mesophile was isolated and characterized. These biopolymer-producing spores propagate easily in Berea cores with permeabilities more than about 500 md. With a specifically formulated nutrient package, they are readily germinated and produce biofilm, which reduces the permeability of the rock. The depth of penetration and the degree of permeability reduction can be controlled by varying injection schemes.
Useful Concepts for Decline-Curve Forecasting, Reserve Estimation, and Analysis
Authors: Fetkovich M. J. , Fetkovich E. J. , Fetkovich M. D.
Published: December 2007

The purpose of this paper is to give engineers responsible for making forecasts and determining reserves for numerous operated or nonoper-ated wells some guidelines and fundamental concepts to allow them to make these forecasts and determinations more quickly and accurately.
Improved Material-Balance Regression Analysis for Waterdrive Oil and Gas Reservoirs
Authors: Sills S. R.
Published: December 2007

An improved material-balance formulation is presented for determining original hydrocarbons-in-place (OHIP) in waterdrive oil and gas reservoirs. The improved formulation reduces the number of unknowns in the regression analysis through the definition of a combined aquifer/reservoir expansion term (CARET). Field examples analyzed with the CARET formulation are presented illustrating the nonunique nature of waterdrive material-balance solutions for OHIP. A method is presented for reality checking the best-fit aquifer parameters obtained from the regression analysis. The CARET material-balance formulation is shown to provide several advantages over existing regression analysis techniques.
Operational Limits of Synthetic Drilling Fluids
Authors: Growcock F. B. , Frederick T. P.
Published: December 2007

In environmentally sensitive areas like the North Sea, synthetic-based drilling fluids are becoming increasingly popular as substitutes for conventional oil-based muds. In many cases, they appear to perform every bit as well as oil-based muds. As currently formulated, some synthetic-based muds are limited to lower temperatures and mud densities and higher oil/water (O/W) ratios than oil-based muds. Limits of these properties can be extended by using high concentrations of surfactants and low-shear rheology modifiers.
A Generalized Well-Management Scheme for Reservoir Simulation
Authors: Fang W. Y. , Lo K. K.
Published: December 2007

A new generalized well-management scheme has been formulated to maximize oil production under multiple facility constraints. The scheme integrates reservoir performance, wellbore hydraulics, surface facility constraints, and lift-gas allocation to maximize oil production. It predicts well performance on the basis of up-to-date hydraulics and reservoir conditions. The scheme has been implemented in a black oil simulator by using separable programming and simplex algorithm. This production optimization scheme has been applied to two full-field models. The oil production of these two full-field models is limited by water, gas, and liquid handling limits at both field and flow-station levels. The gas production is limited by injectivity and gas handling limits. For a 12-year production forecast, the new scheme increased oil production by 3 to 9%.
Drilling Optimization—The Driller's Role
Authors: Reinhold W. B. , Close D. A.
Published: December 2007

For any given drilling operation, several drilling technologies are available to optimize the process of producing a usable borehole. The intent of this process is to conduct the drilling safely and in the most cost-effective manner possible. Our industry has made significant progress in developing improved technologies such as realtime formation evaluation, directional control while drilling, improved bottomhole assembly (BHA) components, and drilling fluids. These and other new technologies have added the requirement for specialized staff at the wellsite and, at the same time, have often reduced the role of the driller. The challenge facing the industry for the foreseeable future is to find a more efficient method of utilizing these technologies while simultaneously reducing the need for certain specialized staff.

This paper analyzes the driller's role and emphasizes his role as the critical link in safely and efficiently drilling a borehole. As the industry moves toward the more cost-effective technologies of computer-based instrumentation, power-handling tools, and automated drilling, the driller's role will need to evolve from one of basic drilling mechanics into that of a real-time drilling supervisor. In this way, the driller (the only 100% real-time link with the drilling process) should become an active member of the wellsite management team, thereby reducing some need for specialized advisory staff.
Field Applications of Steam Foam for Mobility Improvement and Profile Control
Authors: Patzek Tad W.
Published: December 2007

Foams are used to control and improve the injection profile in secondary or tertiary gas-injection processes and reduce gas mobility far from the injectors. Over the last decade, significant progress has been made in the understanding of the complex foam processes in porous rocks. The goal of this paper is to review consistently, albeit somewhat subjectively, several important field tests of foams, compare their performance, and critically evaluate the economic benefits from foam injection. It is shown that early, transient, and usually small oil production responses to surfactant injection are real, and depend critically on the reservoir architecture and gas flood implementation. These early production responses are related to the improvements of gas-injection profile by foam and are often quite profitable. The delayed, but bigger oil production responses are caused by foam propagation into the reservoir and could be very profitable, depending on the injection policy. An outline of an ideal future foam pilot is presented, and important advances in rigorous modeling of foam processes are discussed.
Performance of Multiple Horizontal Well Laterals in Low- to Medium-Permeability Reservoirs
Authors: Retnanto Albertus , Economides M. J.
Published: December 2007

A generalized semianalytical productivity model, accounting for any well and reservoir configuration has been constructed and presented recently. The model allows for the production or injection prediction of any well (vertical, horizontal, deviated) and reservoir configurations in both isotropic and anisotropic media. Partially completed wells can also be simulated. A concern in modern reservoir management is the potential desirability of multiple horizontal laterals, frequently emanating from the same vertical well. Once pseudosteady state is reached, the productivity index differences among various well configurations are diminished. Thus, multiple laterals in higher-permeability formations, draining an assigned "box," may not offer incremental benefits. However, at early time and under transient conditions in low- to medium-permeability reservoirs, the relative productivity improvements provided by multiple laterals may result in sufficient incremental benefits to warrant their drilling. This paper presents a series of parametric studies for a range of reservoir permeabilities and permeability anisotropies for various multiple well configurations. The desirability or lack thereof for these configurations is demonstrated.
The Impact of Corrosion on the Oil and Gas Industry
Authors: Kermani M. B. , Harrop Don
Published: December 2007

The impact of corrosion on the oil industry has been viewed in terms of its effect on both capital and operational expenditures (CAPEX and OPEX) and health, safety, and the environment (HSE). To fight against the high cost and the impact of corrosion within the oil industry, an overview of topical research and engineering activities is presented. This covers corrosion and metallurgy issues related to drilling, production, transportation, and refinery activities.
Egypt's First Subsea Completion: A Gulf of Suez Case History
Authors: El Hawary Ahmed , Hoffman John G.
Published: December 2007

A case history of the Gulf of Suez Petroleum Company's (GUPCO) first remotely controlled subsea completion is provided. The first completion was for well GS 373-2, a previously drilled and tested exploration well located in the south portion of the Gulf of Suez. Subsea technology was utilized to economically justify development of this one well marginal field which was discovered in 1978. Traditional methods proved to be too costly for development, therefore application of a low cost subsea tree was utilized to capture the resources.

In the Gulf of Suez, many fields have been discovered but have not been developed due to low reserves. These marginal projects can have a profound impact on the revenue and shareholder value if an economic method is used to exploit these opportunities. Platform installation was not feasible due to reserve size, hence the well has remained abandoned until recently. Capturing the experience of Amoco in the Gulf of Mexico and in the Dutch North Sea, Gupco was able to build a low cost subsea system which would allow for the economic development of the marginal fields discovered in the past.

This paper presents a summarized look at subsea completion technology. The cost comparison of traditional development methods will be made, given the local cost structure in Egypt. The application of this technology has some limitations and constraints which will be discussed in the paper. Furthermore the actual field installation of Egypt's first remotely controlled subsea tree will be summarized. Also included is a discussion on simple remote controls, and offshore installation operations.
Asphaltene Adsorption Onto Formation Rock: An Approach to Asphaltene Formation Damage Prevention
Authors: Piro Giampietro , Canonico L. B. , Galbariggi Guido , Bertero Luigi , Carniani Carlo
Published: December 2007

In this paper, through a comparative study on static vs. dynamic adsorption of asphaltene onto formation rock, we report how, for the particular asphaltene/formation rock system considered, the dynamic asphaltene adsorption onto formation rock is a continuous phenomenon by which the quantity of adsorbed asphaltene increases continuously. In our opinion, this rather remarkable adsorption behavior may contribute to asphaltene formation damage. In the hypothesis that "prevention" may represent a more economical approach than "removal," we also report a possible "prevention approach" based on formation rock treatment by means of specific chemicals more apt than asphaltenes to be adsorbed onto rock. As a preliminary demonstration, with the aim of assessing qualitatively the potential of our approach, we have pretreated the rock with commercially available asphaltene dispersant and flocculation inhibitors. Although the chosen additives are not commercialized on the basis of their specific adsorption feature, a modest prevention effect has been found. Experimental set-ups and procedures used as a base for a test to rank chemicals with respect to their "asphaltene adsorption" inhibitive effects are also reported.
Improving the Efficiency of Matrix Acidizing With a Succinoglycan Viscosifier
Authors: Jones A. T. , Døvle Marit , Davies D. R.
Published: December 2007

The efficiency of matrix acidizing treatments is becoming more critical, especially as more wells are drilled with long, horizontal sections. Without some sort of selective placement or diversion technique, zones near the point of acid injection or with high injectivity will be preferentially treated. Yet hardware solutions are often prohibitively expensive, and many available diversion techniques are not readily applied in openhole horizontal sections. In this context, viscosified acids offer a potential solution.

An investigation into the placement of gelled acids over a treatment interval has shown that they can greatly improve the uniformity of acidizing. Other studies have revealed that a succinoglycan biopolymer in hydrochloric acid (HCl) exhibits nearly ideal gelled-acid properties over a certain temperature range. To design a gelled HCl treatment, the temperature- and time-dependent rheology of succinoglycan in HCl has been determined. The experimental data have been fit to a model that is used here in an example optimization procedure.
Permeability Prediction by Hydraulic Flow Units—Theory and Applications
Authors: Abbaszadeh Maghsood , Fujii Hikari , Fujimoto Fujio
Published: December 2007

An improved technique based on the concept of hydraulic flow units or hydraulic units (HU's) is presented to calculate permeability distribution in uncored wells. Graphical probability methods, nonlinear regression, and the Ward's analytical algorithm are presented to perform cluster analysis on core data and identify prevailing HU's in a formation. A Bayesian-based probabilistic approach is discussed next to estimate HU's and permeability distributions in logged wells. This is an inverse problem that requires constructing an a priori training database to capture implicit relationships between core-derived HU's and various well log measurements. Information from the database is drawn statistically to infer HU distributions at target logged wells. The method is applied to two heterogeneous reservoirs, a carbonate formation, and a laminated sandstone formation. Comparisons of permeabilities calculated by the HU approach and other conventional techniques are provided that demonstrate the usefulness of the HU method.
Modeling Coiled-Tubing Velocity Strings for Gas Wells
Authors: Martinez John , Martinez Alec
Published: December 2007

Because of its ability to prolong well life, its relatively low expense, and the relative ease with which it is installed, coiled tubing has become a preferred remedial method of tubular completion for gas wells. Of course, the difficulty in procuring wireline-test data is a drawback to verifying the accuracy of the assumptions and predictions used for coiled-tubing selection. This increases the importance of the prediction-making process, and, as a result, places great emphasis on the modeling methods that are used. This paper focuses on the processes and methods for achieving sound multiphase-flow predictions by looking at the steps necessary to arrive at coiled-tubing selection.

Furthermore, this paper examines the variables that serve as indicators of the viability of each tubing size, especially liquid holdup. This means that in addition to methodology, emphasis is placed on the use of a good wellbore model. The computer model discussed is in use industry wide.
A New Analysis of Pressure Decline for Acid Fracturing
Authors: Gu Fagang , Ren Shuquan , Zhao Zhenfeng
Published: December 2007

Conventional pressure-decline analysis has been used successfully to determine the in-situ fluid-loss coefficients and fracture geometries of minifracture tests or full-scale hydraulic fracturing. However, it fails to interpret the pressure-decline data of acid fracturing because it has a different fluid-loss mechanism and a short testing time. This paper presents a new pressure-decline analysis for full-scale acid fracturing or acid minifracturing to estimate fluid-loss coefficients and evaluate fracture geometries for the Perkins-Kern-Nordgren (PKN) model.1,2 The models established after shut-in have comprehensively taken into consideration the influences of compressibility and thermal expansion of fluids (waste acid and CO2 gas produced by reaction) and the rock volume etched away by acid. The effects of formation temperature and reaction heat are also taken into account in this analysis. The analytical solution derived by Nordgren2 for large fluid-loss is used to calculate the fracture-width distribution along a fracture. The short-test-time data for acid fracturing can be interpreted as a simulation technique used in analyzing.

The comparison of the results of conventional analysis and this new analysis for field test data shows that the conventional analysis causes a −56.2% error in the fluid-loss coefficient and underestimates the fluid-loss. The relative errors of the conventional analysis for estimating fluid efficiency and hydraulic-fracture length and width occur 186.2%, 220.8%, and 16.5% respectively.
Early Identification of Reservoir Compartmentalization by Combining a Range of Conventional and Novel Data Types
Authors: Smalley P. C. , Hale N. A.
Published: December 2007

Reservoir compartmentalization (vertical and lateral) is often a major uncertainty at the field appraisal stage, impacting important investment decisions. Unfortunately, the most definitive compartmentalization data (dynamic production data) are not usually available so early in field life. This paper illustrates how early indications of compartmentalization can be achieved by integrating various types of conventional and novel data. Using an example from the Ross oilfield, U.K. Continental Shelf (UKCS), we demonstrate how integration of oil compositional data (molecular maturity parameters, gas chroma-tography [GC] fingerprinting, pressure-volume-temperature [PVT] data) with pressure, well test, and fault seal analysis revealed the presence of several sealing faults, and thus enabled the field to be described in terms of its likely segmentation. Vertical compartmental-ization was investigated using a combination of oil geochemistry (maturity, GC fingerprinting), water composition (residual salt analysis), and high-resolution stratigraphy, revealing a continuous shale that has a lateral extent of > 5 km; it divides the reservoir into two main layers. The results of this study helped to decrease uncertainty in field development planning. The key message is that there are many tools available to aid in assessing compartmentalization, but individually they each only give part of the picture. It is therefore important to use several tools in combination.
Reparameterization Techniques for Generating Reservoir Descriptions Conditioned to Variograms and Well-Test Pressure Data
Authors: Reynolds A. C. , He Nanqun , Chu Lifu , Oliver D. S.
Published: December 2007

Recently, we have shown that reservoir descriptions conditioned to multiwell pressure data and univariate and bivariate statistics for permeability and porosity can be obtained by techniques developed from inverse problem theory. The techniques yield estimates of well skin factors and porosity and permeability fields which honor both the spatial statistics and the pressure data. Imbedded in the methodology is the application of the Gauss-Newton method to construct the maximum a posteriori estimate of the reservoir parameters. If one wishes to determine permeability and porosity values at thousands of gridblocks for use in a reservoir simulator, then inversion of the Hessian matrix at each iteration of the Gauss-Newton procedure becomes computationally expensive. In this work, we present two methods to reparameterize the reservoir model to improve the computational efficiency. The first method uses spectral (eigenvalue/eigenvector) decomposition of the prior covariance matrix. The second method uses a subspace method to reduce the' size of the matrix problem that must be solved at each iteration of the Gauss-Newton method. It is shown that proper implementation of the reparameterization techniques may significantly reduce the computational time required to generate realizations of the reservoir model, i.e., the porosity and permeability fields and well skin factors, conditioned to prior information on porosity and permeability and multiwell pressure data.
Errors and Uncertainties in Reservoir Performance Predictions
Authors: Bu Tor , Damsleth Eivind
Published: December 2007

While the uncertainty related to mapping/quantification of hydrocarbons initially in place is well understood, there are problems regarding the sources and propagation of errors/uncertainties in reservoir simulation. Because reservoir models use measured data from only a small fraction of the total reservoir volume, the challenge is to construct a reservoir model that uses the available data and minimizes errors in simulation results.

Several recent studies have aimed at performing a total uncertainty analysis of reservoir simulation results. Underlying such work is usually a number of hypotheses/assumptions that are not always clearly expressed.

In this paper, we will discuss implications of some of the statistical methods that are commonly applied in uncertainty analysis and construction of a geological model. The Bayesian approach, where additional data can reduce uncertainties, is emphasized.

Several papers have demonstrated large variations in parameters obtained from routine and special core analysis on samples originating from the same geological building block (lithofacies). This variation, which sometimes may be difficult to dissolve from uncertainty in the measurements, must be accounted for in models that describe small scale variation.
Trials of Threshold Hydrate Inhibitors in the Ravenspurn to Cleeton Line
Authors: Corrigan A. , Duncum S. N. , Edwards A. R. , Osborne C. G.
Published: December 2007

A series of field trials to test threshold hydrate inhibitors (THI's) has been carried out in the wet gas line connecting the Ravenspurn and Cleeton fields. These BP-operated assets are located in the U.K. sector of the southern North Sea, approximately 50 miles offshore of the Dimlington gas terminal. The flow line is 13 miles long, 16 in. in diameter with a normal production rate of 195 MMscf/D. During the trial, the line pressure was maintained at 75 barg (1,088 psig) for a throughput of 90 MMscf/D. When methanol injection into the line was stopped, hydrates readily formed. Conditions in the line were 8 to 9°C inside the equilibrium hydrate curve. This resulted in an estimated 50 tonnes of hydrate accumulating in the line over a 4-day period. At these same conditions, THI injected at a dose rate of 3,000 to 5,000 ppm (parts per million on the basis of total water production) prevented hydrate formation. After 6 days, the chemical supply was exhausted, and after a delay during which chemical was flushed from the system, hydrates formed as before. The robustness of the chemical to line shut-in conditions was also confirmed. These trials conclusively show that a low dosage chemical can be used for hydrate suppression in a wet gas pipeline system.
Application of Streamtube Techniques to Full-Field Waterflood Simulation
Authors: Emanuel A. S. , Milliken W. J.
Published: December 2007

A comparison between streamtube and finite-difference (FD) modeling for waterfloods is presented to show the utility of streamtubes as a reservoir modeling technique. The streamtube formulation follows most of the classic techniques presented in the literature. Areal sweep in the model is determined by streamlines developed on the basis of unit mobility ratio and corrected for changing mobility ratio by the method of Martin and Wegner.1 Displacement along the streamtubes is calculated by a Welge2 construction with vertical heterogeneity represented by Dykstra-Parsons3 (DP) layering. This work differs from previous efforts because wells are individually history matched by assignment of DP coefficients on a well-by-well basis. Suggestions are made for the further application of the saturation distribution resulting from the model.

Two applications of the technique are described. The first is a comparison between FD and streamtube modeling for a waterflood based on the Ninth SPE Comparative Solution Project.4 This application is designed to describe the basis of the streamtube technique in the context of a standardized industry problem. The second application is for a study of the Kaybob North reservoir that shows model development and history matching for a 100 + -well field with a 30-year history and a number of realignments.
Application of Kinetic Inhibitors to Gas Hydrate Problems
Authors: Notz P. K. , Bumgardner S. B. , Schaneman B. D. , Todd J. L.
Published: December 2007

Laboratory and field tests since 1991 have shown the feasibility of replacing the classical inhibitors (methanol and ethylene glycol) with kinetic inhibitors. Although the kinetic inhibitors have limitations, they have been shown to be effective in preventing the formation of hydrate plugs in field situations. In many cases, there is an economic advantage to using the kinetic inhibitors. An analysis of the conditions in the production facilities must be done to ascertain the applicability of a kinetic inhibitor. The data and tests that are required to determine the applicability of a kinetic inhibitor are discussed. The application of kinetic inhibitors to flowlines in producing fields is presented.

The cost to the petroleum industry to inhibit the formation of gas hydrates is greatly increasing with the development of offshore reservoirs. Gas hydrates are likely to form in subsea flowlines unless the water is removed down to the lowest dew point encountered, highly effective insulation is used, or inhibitors are used. The first two possibilities are generally prohibitively expensive or the technology for subsea application does not exist. In many cases, kinetic inhibitors offer lower cost alternatives to classical inhibitors and are more environmentally friendly.

The results show that kinetic inhibitors can be applied economically to field-production systems. This is an area where there is very little published information at this time. In addition, the data (both field and laboratory) that are required to verify the effectiveness of a kinetic inhibitor are illustrated.

This information will help producers with hydrate problems evaluate the use of kinetic inhibitors. Savings in the range of 50% of the chemical costs and reduced downtime can be realized in many cases.
Performance of a Longitudinally Fractured Horizontal Well
Authors: Valkó P. , Economides M. J.
Published: December 2007

This work is an attempt to effectively unify two of the most common modern techniques for improved and accelerated petroleum production: horizontal wells and hydraulic fracturing. Greatly dependent on the in-situ stress anisotropy, hydraulic fractures are invariably vertical with a well-defined azimuth. Horizontal wells drilled along the minimum stress would accept transverse hydraulic fractures. This configuration, with multiple treatments, has been already expounded upon in the literature and is appropriate for low-permeability formations. Higher-permeability formations, the range of which has been expanded greatly with the emergence of frac&pack treatments, favor the drilling of horizontal wells along the maximum stress, resulting in a longitudinal hydraulic fracture configuration. The purpose of this paper is to provide a means to estimate the productivity index of such well completion, to compare it with that of a fractured vertical well, and to allow for sound production engineering decisions based on anticipated well performance.
Evaluation and Selection of Drill-ln-Fluid Candidates To Minimize Formation Damage
Authors: Hodge R. M. , Augustine B. G. , Burton R. C. , Sanders W. W. , Stomp Donna Atkinson
Published: December 2007

Conoco drilled and completed a horizontal well in a depleted, high-permeability oil reservoir. The formation is an unconsolidated, clean sandstone with absolute permeability over 3,300 md. The unconsolidated nature of the formation combined with its low pressure and high permeability caused concerns regarding hole stability, fracturing, excessive fluid loss, and differential sticking. To identify the best drill-in fluid (DIF) for the horizontal section, the evaluation of fluid candidates focused on both drilling properties and formation/completion-damage potential. The testing compared fluid performance in standard drilling-fluid tests, low-shear rheology at elevated temperature, dynamic fluid-loss behavior at elevated temperature, and core-flow tests. The flow testing was performed with cores from an offset well to simulate damage caused by DIF exposure and to evaluate remedial treatment options. Also, a new laboratory-scale procedure was developed to observe the tendency of prepacked screens to be plugged by DIF filter cake and unconsoli-dated formation sand.

In addition to the laboratory testing, a review of the drilling and completion operations is presented, including performance of the drilling fluid at high overbalance pressure ( ≈ 2,600 psi) and the design and execution of subsequent remedial treatments. The production history is discussed and related to laboratory observations regarding cleanup and remedial-treatment effectiveness.
Long-Zone Squeeze Gravel Packs in Geopressured Reservoirs in the Gulf of Mexico
Authors: Bruner S. D. , Lau H. C. , Morgenthaler L. N. , Bernardi L. A. , Kielty J. M.
Published: December 2007

Laboratory studies were conducted to determine the completion techniques for two wells in the Gulf of Mexico with well angles of 35 to 45°, completion intervals of about 400 ft, bottomhole temperatures of 222°F, and requiring a completion brine with density up to 17.0 lbm/gal. Three critical issues—fluid-loss control, pregravel-pack acid stimulation, and internal gravel packing—were studied.

Laboratory studies showed that an activated hydroxyethyl-cellulose (HEC) pill could be designed to control the fluid loss for more than 30 hours, even at a bottomhole temperature of 222°R In addition, a high-rate acid stimulation could be employed to ensure that as many perforations as possible were open to accept gravel-pack sand. Physical model studies also showed that a high-rate squeeze waterpack provided the required effective perforation and annular packing for the target wells despite the long completion interval.

These techniques were successfully implemented. Initial production data suggest that both wells, still under choke, are producing at expected rates, with low downhole drawdown.
Development and Field Trial of Two Environmentally Safe Water-Based Fluids Used Sequentially to Free Stuck Pipe
Authors: Fisk J. V. , Wood R. R. , Kirsner Jeff
Published: December 2007

Diesel-based spotting fluids have historically been used to free differentially stuck pipe. Increasing environmental regulatory pressures have prompted the development of environmentally acceptable water-based spotting fluids. In spite of their widespread application, these new fluids have had only sporadic success in freeing differentially-stuck pipe in the field.

An extensive laboratory research project was initiated to identify potential chemistries that could offer increased performance and maintain environmental acceptability. Literature reviews revealed that previous spotting fluid research had focused mainly on the spotting fluid providing lubrication between the drillpipe and mud filter cakes. Laboratory data also revealed that the best preforming conventional spotting fluids were highly toxic to mysid shrimp.

In accordance with the new findings, a two phase spot was developed. A field application is detailed that validated the concept of the two phase spot and its method of application.
Advanced Torque-and-Drag Considerations in Extended-Reach Wells.
Authors: Payne M. L. , Abbassian Fereidoun
Published: December 2007

Excessive torque and drag can be critical limitations in extended-reach drilling (ERD). This paper details issues related to torque-and-drag prediction, monitoring, and management in ERD wells. Results are presented from sensitivity analyses of extreme ERD trajectories such as 7- to 8-km departures at 1600 m true vertical depth (TVD). Several such wells have now been successfully drilled at the Wytch Farm oilfield using results from these studies. In such high-angle ERD wells, compression generated in the drillpipe during tripping and sliding operations can exceed the critical buckling load and cause the drillpipe to buckle. As a result, buckling initiation and post-buckling analyses are used to quantify the extent and severity of buckling and the associated increases in drag forces and pipe stresses. The paper addresses the importance of drilling data in calibrating torque/drag models to capture the continual changes in drilling parameters and operating conditions. The paper presents a number of field case studies where analyses have been conducted to directly assist drilling operations. This paper should be of high interest to engineers executing, planning, or evaluating ERD operations.
Enhanced Waterflooding Design With Dilute Surfactant Concentrations for North Sea Conditions
Authors: Michels A. M. , Djojosoeparto R. S. , Haas Henk , Mattern R. B. , van der Weg P. B. , Schulte W. M.
Published: December 2007

Efficient selection procedures for surfactants have been applied to design a low-concentration surfactant-flooding process for North Sea oilfield application. Anionic surfactants of the propoxy ethoxy glyceryl sulfonate type can be used at 0.1 wt% concentrations together with sacrificial agents and without a polymer drive. Currently estimated unit technical costs (UTC's)—at 8% — for application in the North Sea oil fields range from $81 to $94/incremental m3, without taking uncertainty factors into account. Including such factors would likely add another $31/m3 to the costs.
A Critical Review of the Use of Pseudorelative Permeabilities for Upscaling
Authors: Barker John W. , Thibeau Sylvain
Published: December 2007

The properties and limitations of different dynamic pseudorelative permeability methods are summarized. Severe difficulties common to all methods are discussed: choosing the number and locations of the coarse-grid rock types, defining the simulations from which the pseudos are generated, and the dependence of the pseudos on well rates and positions. It is concluded that, in practice, pseudos cannot be used reliably to scale up from a "fine-grid" geological model to a "coarse-grid" fluid-flow model except for cases where capillary or gravity equilibrium can be assumed at the coarse-gridblock scale. Scaling up from the core scale to the geological model is more likely to be possible because capillary forces are more important at smaller scales. A practical approach to the dynamic upscaling problem is outlined, but one should not expect that the effects of the detail in the geological model will be captured more than qualitatively.
Neutron Logs Improve Interpretation of Foamed Cement, Even in Concentric Casing
Authors: Harness P. E. , Frank W. E.
Published: December 2007

A new method of foamed cement evaluation using a comparison of open-hole and cased-hole neutron logs is described to complement existing techniques using acoustic cement evaluation logs. Together, it is possible to identify neat cement, foamed cement, fluid, and air behind pipe. Favorable results are achieved in a case study, whether the annulus is bounded by formation or a larger casing string.