bluuebunny/crossref_metadata_2025 huggingface dataset:
Pseudo-Relative Permeability for Well Modeling
Authors: Emanuel A.S. , Cook G.W.
Published: December 2007

Several authors have described the use of pseudo-relative-permeability curves for modeling pseudo-relative-permeability curves for modeling the vertical performance of formation flow in areal reservoir simulators. The pseudo curves are usually determined from small cross-section or three-dimension models and then incorporated into large-scale areal models. The concept of pseudo-relative permeability can also be extended to the vertical performance of individual wells by a technique analogous to that for formation flow. In a cross-section model, the production of phase p from a well with nc completions can be expressed as(1)

Eq. 1 follows the form of the well potential equation of Ref. 4. For an areal model in which the well has only one completion, the production is(2)

The cross-section model can be constructed with the vertical detail necessary to account for phase segregation, partial penetration, etc. To obtain the same well performance in the areal model, we desire(3)

or combining Eqs. 1 through 3,(4)

If the cross-section model has been divided into nl layers, then an areal model block represents a composite of the nl layers and a well a composite of nc completions. Therefore, the following approximations are made.(5)

and(6)

Combining Eq. 4 through 6, the pseudo-relative permeability for the areal model well is obtained: permeability for the areal model well is obtained:(7)

The corresponding saturation is(8)

The wellbore pressure in the areal model, PwA, can be assumed to be an appropriate average of the Pw calculated in the cross-section model. Eqs. 6 Pw calculated in the cross-section model. Eqs. 6 and 8 am appropriate for an areal block equivalent to one column of the vertical model. If the areal block is larger, then the pressure and saturation must be averaged over the volume encompassed by the areal block.

P. 7
Cement Spacer Fluid
Authors: Carney Leroy
Published: December 2007

Introduction

Completion problems during the cementing of casings or liners in wellbores have confronted the oil and gas industry for many years. Generally, after the borehole has been drilled, the drilling mud employed is displaced by the cement used in cementing the casing or liner. Compositions and properties of drilling muds and cement slurries vary widely. Such variation may result in detrimental physical and chemical reactions at the interfacial contact. For physical and chemical reactions at the interfacial contact. For example, when a high-viscosity, high-density drilling fluid is used, the incompatibility may contribute to channeling in the annulus and may prevent a satisfactory cement-to-formation bond. As a result, communication may occur between zones and possibly even to the surface.In view of the persistence of those problems, a serious need was recognized for a single type of spacer fluid that could be employed effectively between the cement slurry and any type of mud.

Criteria for Development

The following criteria were established as goals for research efforts in developing a universal spacer fluid:1. It should be compatible with all oil-base muds, invert-emulsion muds, and water-base muds, including chemical gel muds and polymer muds.2. It should not affect cement slurry viscosity, especially high-weighted cements at elevated temperature.3. It should not appreciably change the pumping time of cement slurries.4. It should allow for being weighted to any density required in the field.5. It should be able to tolerate high solids, as mud cake may be picked up, adding to what often is already a high solids content.6. It should tolerate the addition of wetting agents, dispersants, friction reducers, and retarders when needed.7. It should keep the calcium from cement slurries out of water-base muds and, especially, out of polymer muds.8. It should have low-fluid-loss properties.9. Its flow properties should permit turbulence at low pumping rates for better mud removal.10. It should be usable between various types of incompatible drilling fluids during displacement.11. It should be easy to mix and handle in the field.12. It should allow for the use of a variety of fluids in formulating the liquid phase so that specialty fluids are not necessary. In most cases the fluids are already on location.A field survey was conducted on several wells in South Texas and Mississippi to determine what cementing problems were being encountered with various drilling fluids and cements. The survey indicated that oil-base fluids and invert emulsions cause most of the problems. This is especially true when the oil-base mud contains a high-salinity internal phase composed of saturated sodium chloride or calcium chloride. As compatibility with oil-base muds and invert-emulsion muds as well as compatibility with aqueous slurries is necessary for an ideal spacer fluid, an emulsion was considered for development.

JPT

P. 856
Air and Gas Drilling
Authors: Moore C.L. , Lafave V.A.
Published: December 2007

The San Juan Basin of Northwestern New Mexico gave the impetus to the drilling industry to extend the use of gas drilling. This in turn brought about extended use of compressed air as a drilling medium, especially in wildcatting.

Many new drilling problems have developed with the advent of this type of drilling. Air drilling experiences have reached a point where problems such as water entry, crooked hole conditions, and the shortage of suitable air compressor equipment have at least partially been solved. Air drilling has opened an entirely new field for design and invention.

Introduction and Review of the San Juan Operations

The San Juan Basin of Northwestern New Mexico gave the oil and gas industry its first practical application for air drilling. This might be compared with the start the Rangely field in Colorado gave to the diamond bit.

Since 1951, the El Paso Natural Gas Co. has completed 400 wells in this Basin using gas as a circulating medium. It is estimated that there are between 800 and 1,000 wells that have been gas-completed in this area. These wells were completed principally in the Mesa Verde formation of Cretaceous Age, which consists of 800 ft of interbedded sand, shales, and coal at an average depth of 5,000 ft. This gas formation has a very low porosity, low permeability, and a reservoir pressure of approximately 1,250 psi.

This field would have been impossible to develop without gas drilling. Drilling mud completely blocked the producing formation and the only alternative, prior to gas drilling, had been cable tool operations. It often took five to eight weeks to drill the 800-ft Mesa Verde section.

After shooting this section with as much as 2,300 qt of solidified nitroglycerin, the cleaning out process further increased the hazards of cable tool operations. Cable tool drilling in this formation brought about seemingly endless fishing jobs. It was not uncommon to have as many as three strings of tools in the hole at one time, and in a number of cases from one to two of these were left in the hole. Rarely was a Mesa Verde well completed without at least one fishing job.
High-Accuracy Implicit Finite-Difference Simulations of Homogeneous and Heterogeneous Miscible-Porous-Medium Flows
Authors: Meiburg Eckart , Chen C.-Y.
Published: December 2007

A novel computational algorithm for the direct numerical simulation of miscible-porous-media flows is developed and applied that offers multiple benefits. It is based on the streamfunction-vorticity formulation of Darcy's law and resolves all physically relevant length scales including diffusion. By employing an implicit discretization based on compact finite differences, it combines ease of implementation and the ability to handle nontrivial geometries with the superior computational accuracy usually reserved for spectral methods. The formal accuracy is O(Δx4,Δt2), although diffusion terms are discretized with O(Δx6). Test calculations are performed that provide a quantitative comparison with linear stability results for strong mobility contrasts in the practically relevant-quarter five-spot configuration. The excellent agreement, both with regard to the algebraic growth rate as well as the preferred wave number, demonstrates the very low levels of numerical diffusion, thereby eliminating grid orientation effects. The capabilities of the numerical method are furthermore demonstrated by means of representative calculations for both homogeneous and heterogeneous displacements. Among other findings, these simulations exhibit a minimal recovery efficiency for intermediate values of the correlation length of the permeability heterogeneities.
Pore-Level Network Modeling of Three-Phase Capillary Pressure and Relative Permeability Curves
Authors: Mani Vanita , Mohanty K. K.
Published: December 2007

A three-dimensional (3D) pore-level network model is developed to calculate three-phase capillary pressure and relative permeability curves. The model combines a description of pore space morphological features and three-phase displacement physics to model capillarity-controlled gas invasion into a water-wet medium containing oil and water. The gas/water capillary pressure curves in three-phase systems depend on the fluid saturations, the spreading coefficient, and the oil/water capillary pressure. Water relative permeability, for the strongly water-wet system modeled, is a function of its saturation alone. Gas and oil relative permeability curves depend on the gas and oil saturation, respectively, the saturation history, and the spreading coefficient. The displacement of oil as a response to changing the capillary pressure in a three-phase system cannot be described by existing models for multiphase flow. A modification of Darcy's law is proposed to describe capillary pressure induced oil transport in three-phase systems.
The Use of Coiled Tubing During Matrix Acidizing of Carbonate Reservoirs Completed in Horizontal, Deviated, and Vertical Wells
Authors: Thomas R. L. , Saxon Alan , Milne A. W.
Published: December 2007

A laboratory and field study directed at improved well performance of horizontal wells is discussed. During the study, several wells were matrix acidized by use of bullhead and coiled tubing (CT) placement techniques in carbonate reservoirs. The study indicates that acid placed with CT diverted with foam, or a temporarily crosslinked gelled acid (TCGA) system, provides excellent zone coverage and damage removal. Conventional bullhead techniques do not result in effective damage removal. The study emphasizes the evaluation of the treatment results and the development of improved acidizing techniques.

Computer simulations of matrix acidizing indicate that proper placement techniques are essential. This observation is supported by field data in wells completed in carbonate reservoirs. The keys to successful damage removal are the placement of acid through CT and proper diversion. Production-logging and well-performance data support this claim. The proposed treatment is applicable in both horizontal and vertical wells completed in carbonate reservoirs.
Coiled-Tubing Deformation Mechanics: Diametral Growth and Elongation
Authors: Tipton S. M.
Published: December 2007

Coiled tubing (CT) endures unique cyclic stress and strain histories. The loading imposed on pressurized CT can trigger deformation mechanisms resulting in incremental plastic diametral growth and elongation. This growth occurs despite the fact that both the hoop stress and net axial stress from tension are well below the material yield stress. The most dominant factors controlling the deformation behavior of CT are the bending/straightening cycles associated with the spool and gooseneck. The interaction of the bending stresses and strains with those from axial loading and pressure result in plastic elongation and diametral growth. Severe cyclic plasticity imposed by these events actually changes the structure of the CT material, causing a corresponding change in mechanical properties. The material properties in a section of CT along a string are thus dependent upon the localized service loading history.

The operating parameters that control the loading on a section of CT are discussed in terms of the tubing geometry, the above-surface deployment equipment and the subsurface environment. With the load history characterized in terms of imposed stresses and strains, mechanisms that lead to diametral growth and elongation are demonstrated from the standpoint of simple material plasticity models. Refined models are described, based on more sophisticated plasticity relations, capable of characterizing transient behavior and multiaxial effects. Implications from these results for depth calculation are discussed.
Corrosion Problems in Below-Grade Wellhead Equipment and Surface Casings
Authors: Farooqui M. A. S. Z. , Bitar G. E.
Published: December 2007

Inspection of the below-grade wellhead equipment has shown corrosion damage to the buried landing base, casing spools, and surface casing, especially in water injection and supply wells in onshore fields in Saudi Arabia. In this paper, we describe the problem and examine possible reasons for the occurrence of corrosion. Procedures and standards that have been developed to regularly inspect all wells, perform the required repair work, and provide durable protection with field-applied corrosion-resistant coating are also discussed in detail.
Quantifying Acid Placement: The Key to Understanding Damage Removal in Horizontal Wells
Authors: Jones A. T. , Davies D. R.
Published: December 2007

The placement of acid over the entire wellbore interval can be the key to successful stimulation treatments in wells with long (often horizontal) completion intervals. In this paper, we discuss computer simulations performed to determine how fluids are distributed in the wellbore during acidizing treatments. One of the novel aspects of these simulations is the inclusion of wellbore effects arising from the transient flow of acid and diverter along the wellbore. The results suggest a possible cause of some of the poor stimulation performances observed in the field when acid was injected without diversion or selective-placement techniques. Such situations can result in the acid contacting only a small fraction of the treatment interval. The simulations also show how making the acid viscous could have improved the stimulation performance.
A Volumetric Analysis of Almond Formation (Cretaceous, Mesaverde Group) Gas Production in the Coal Gulch-Echo Springs Standard Draw Field Complex, Washakie Basin, Southwest Wyoming
Authors: Burch D. N. , Cluff R. M.
Published: December 2007

The Coal Gulch-Echo Springs-Standard Draw field complex is one of the largest commercial gas accumulations in the Rocky Mountain region with over 1 Tcf of gas of recoverable reserves. Gas is produced from both the Upper Almond barrier bar and shoreline sandstones at the top of the Mesaverde Group (Upper Cretaceous) and from underlying Main Almond fluvial and marginal marine sandstones.

Some recently published models suggest that although the bulk of the produced gas in the fields is from the Upper Almond bar interval, simple volumetric calculations can only account for about 50% of the estimated ultimate recovery from this reservoir. These models imply that the depleting Upper Almond reservoir might be actively recharged by gas leakage from deeper Main Almond sandstones, with contributions from the deeper reservoirs of up to 10 to 30 Bcf of gas per well. This is in stark contrast to typical Main Almond-only producers outside the field area, which have mean reserves of less than 1 Bcf of gas and rarely produce more than 2 Bcf of gas per well. The implication is that the Upper Almond bar sand acts as a gas flow conduit, and its presence is required for efficient drainage of the Main Almond.

We determined the gas in place (GIP) for all field wells drilled before 1993. The GIP within the Upper Almond reservoir only was determined by detailed openhole log analysis and volumetric mapping to be 1,050 Bcf of gas. Total reserves from all producing intervals (Upper Almond and Main Almond combined) are estimated by decline curve analysis to be 1,003 Bcf of gas. The Main Almond lenticular reservoirs contribution to total production is then assumed to be statistically similar to Main Almond-only producers outside the field area, giving an estimated total contribution from Main Almond completions of 96 Bcf of gas; therefore, the recovery factor from the Upper Almond alone is estimated to be (1003 — 96)/1050 = 86%. We conclude that field volumetrics do not support a disproportionate contribution of Main Almond gas to the total field production, nor does the volumetric analysis support the active reservoir recharge hypothesis.
Applying Technical Limit Methodology for Step Change in Understanding and Performance
Authors: Bond D. F. , Scott P. W. , Page P. E. , Windham T. M.
Published: December 2007

This paper presents an alternative planning approach to the drilling and completion process, technical limit, which has resulted in a step change in Woodside's performance. Three new wells and six subsea completions were finished 20% under budget with this tool and with a simple philosophy characterized by the following questions.

What is current performance? What is possible? What is needed to get there?

The target was to drill a directional well in 20 days when the previous best time was 42 days. A target of 12 days was set on subsea completions, although a conventional approach had previously been 20+ days.

The methodology was to ask what would be possible if everything went perfectly on every operation making up the well time. This is not the usual trouble free time but a well time built up of individual components, with each component representing its theoretical best performance.

Details of how the approach was used to plan, and operational data that confirm that the technical limit can be approached are presented. As a result, the well construction performance delivered step change improvement when managed against the technical limit.
A Simple Model for Collapse and Post-Col apse Behavior of Tubulars With Application to Perforated and Slotted Liners
Authors: Abbassian Fereidoun , Parfitt S. H. L.
Published: December 2007

This paper describes a simple method of evaluating the collapse strength and post-collapse behavior of oil field tubulars subjected to external pressure. The method is based on elastic ovalization and subsequent plastic collapse by formation of a four-hinge mechanism. The resulting predictions of collapse strength are compared with available collapse test data, and other existing collapse equations. For post-collapse behavior, model predictions are compared with available experimental and numerical data. The main attraction of the approach is its versatility, demonstrated through application to collapse of perforated and slotted liners, prepacked screens, and its extension to collapse under non-uniform loading.
Analytical Calculation of Coarse-Grid Corrections for Use in Pseudofunctions
Authors: Hewett Thomas A. , Suzuki Koichi , Christie Michael A.
Published: December 2007

We present a new analytical approach for calculating the corrections to pseudofunctions required to account for discretization on a coarse grid. The approach is based on the method of characteristics and yields an expression for the average saturation in a cell as a function of the outlet face saturation similar to one presented by Welge.1 The method accounts for the appropriate averaging volumes for saturation and total mobility to be consistent with an underlying finite difference scheme that uses upstream mobility weighting for the interblock transport terms. The corrections required to account for coarse-grid effects depend only on the ratio of the distances from the injection boundary to the inlet and outlet faces of a discrete gridblock. A direct consequence of this conclusion is that the modifications of relative permeability for the discrete representation are independent of gridblock size and the total number of gridblocks used in the discretization. For a uniform discretization, they depend only on the number of the gridblock, with the first gridblock being that immediately downstream of the injection boundary. The consistent treatment of the averaging volumes for saturation and total mobility produces the unexpected result that the correct form for the discretized relative permeabilities does not converge to the rock curves, even for very large numbers of gridblocks along the flow path.

The results obtained reproduce exactly analytical solutions for fractional flow and pressure drop. The calculated relative permeabilities are frequently nonmonotonic, and may rise above their end point values. Although the results obtained so far are only one-dimensional (1D), the method offers a way of separating the effects of heterogeneity from coarse-grid effects, which may offer a significant improvement in the ability of current upscaling techniques to account for both heterogeneity and coarse-grid effects.
Injection-Well Testing To Optimize Waterflood Performance
Authors: Robertson D.C. , Kelm C.H.
Published: December 2007

A method for injection-well testing is presented that is designed to optimize injection-well operating conditions and to maximize oil recovery from a waterflood without causing unnecessary, damage to the reservoir. This is accomplished by instituting a systematic program for data collection and testing on injection wells.

Introduction

During the late 1950's and early 1960's, West Texas waterflood experiences, such as premature water breakthrough and poor sweep efficiency caused by improper injection-well operation, indicated the need for a systematic procedure for optimizing injection-well operation.

Many waterflood projects were initiated with peripheral or other dispersed patterns having a low ratio of injection wells to producing wells. During the 1960's, when allowables in prorated states started increasing, individual per-well injection rates often were increased to keep abreast of increased withdrawals. These increases sometimes resulted in performance problems that indicated the need for a better understanding of the reservoir and the factors that affect it during waterflood operations. Thus, there evolved a need for a systematic procedure for maximizing injection and producing rates, while allowing for adequate surveillance of reservoir and operating conditions to preclude any reservoir damage that might jeopardize waterflood recovery.

This paper presents a philosophy and method for injection-well testing for optimizing injection-well operation, thus maximizing recovery from a given waterflood pattern. Injectivity is optimized by instituting a planned series of step-rate tests, pressure falloff tests, profile surveys, and temperature surveys during an initial start-up period of about I year, and by continuously collecting and analyzing rate and pressure data, pressure transient data, and profile data throughout the remaining life of the injector.

Objectives and Basis for Injection-Well Testing

The first objective of the systematic injection-well testing approach is to allow maximum pressure differential between the injector and the producer within formation fracture pressure restraints. A simple application of Darcy's law to injection wells shows injection rate to be proportional to pressure differential. Consequently, higher injection rates should result in quicker response and higher production rates.

For several reasons it is imperative that this maximum pressure differential be attained below formation fracture pressure. First, the fracture caused by injecting above the formation fracture pressure is not necessarily limited to the oil pay. Fracturing can be to an aquifer or to a nonproductive interval. Thus, injecting above the formation fracture pressure can result in significant ineffective injection that, if carried to extremes, could result in less water effectively sweeping the oil pay. Second, when injecting above the formation fracture pressure, the direction of fracturing is not predictable.

JPT

P. 1337^
Least-Squares Finite-Element Method To Predict Areal Composition Variations in Large Hydrocarbon Reservoirs
Authors: Biswas Deepankar , Carey G. F.
Published: December 2007

A method is proposed to calculate the areal compositional variations in large hydrocarbon reservoirs in the presence of thermal gradients. A model is developed from the fundamental equations of change for a multicomponent reservoir fluid mixture in a porous medium. The fluxes are obtained from nonequilibrium thermodynamics, and expressions are derived for mass diffusion coefficients. The thermodynamic properties are calculated by use of the Peng-Robinson equation of state (PR-EOS). Under the condition of stationary state, the governing equations are solved by use of the least-squares finite-element method (LSFEM) subject to specified sampling concentrations as data at several well sampling sites. The results are in good agreement with validation simulations based on a similar finite difference solution.
Inflow Performance and Transient Pressure Behavior of Selectively Completed Vertical Wells
Authors: Yildiz Turhan , Cinar Yildiray
Published: December 2007

This paper presents new methods to estimate the inflow performance and transient pressure behavior of selectively completed vertical wells. In the first part, inflow performance of wells perforated at several intervals along the producing formation is investigated. It is observed that formation anisotropy, total perforated length/formation thickness ratio, and mechanical skin distribution caused by formation damage are the parameters controlling the well productivity.

In the second part, transient pressure and pressure-derivative response of selectively perforated wells are modeled and examined. A new interpretation technique, which combines the conventional semilog straightline analysis and type-curve matching method, is presented to determine reservoir parameters.
The Combined Effect of Near-Critical Relative Permeability and Non-Darcy Flow on Well Impairment by Condensate Drop Out
Authors: Blom Saskia M. P. , Hagoort Jacques
Published: December 2007

We present a comprehensive numerical method to calculate well impairment based on steady-state radial flow. The method incorporates near-critical relative permeability and saturation-dependent inertial resistance.

Example calculations show that near-critical relative permeability, which depends on the capillary number, and non-Darcy flow are strongly coupled. Inertial resistance gives rise to a higher capillary number. In its turn, the improved mobility of the gas phase caused by a higher capillary number enhances the importance of the inertial resistance.

The effect of non-Darcy flow is much more pronounced in gas condensate reservoirs than in dry gas reservoirs. Well impairment may be grossly overestimated if the dependence of relative permeability on the capillary number is ignored.
Horizontal Well IPR Calculations
Authors: Thomas L. K. , Todd B. J. , Evans C. E. , Pierson R. G.
Published: December 2007

This paper presents the calculation of near-wellbore skin and non-Darcy flow coefficient for horizontal wells based on whether the well is drilled in an underbalanced or overbalanced condition, whether the well is completed openhole, with a slotted liner, or cased, and on the number of shots per foot and phasing for cased wells. The inclusion of mechanical skin and the non-Darcy flow coefficient in previously published horizontal well equations is presented and a comparison between these equations is given. In addition, both analytical and numerical solutions for horizontal wells with skin and non-Darcy flow are presented for comparison.
Chemistry and Field Application of an Improved Continuous-Mix Gelled Oil
Authors: Maberry L. J. , McConnell S. B. , Tanner K. V. , Hinkel J. J.
Published: December 2007

The introduction of water-base fracturing fluids to water-sensitive formations can be detrimental to well performance. Gelled oil fracturing fluids are often used in water-sensitive formations. However, temperature limitations have typically been associated with gelled oil fluids, especially those used in continuous-mix applications. The chemistry and field application of an improved continuous-mix gelled oil system for use at reservoir temperatures between 75 and 300°F are described. A brief history of oil gelation and phosphate ester chemistry is presented, followed by a discussion of new complexation chemistry. Laboratory data supporting fluid performance are provided. A treatment evaluation is presented on 90 wells fractured in the Wyoming North La Barge area, from August 1994 to October 1996. Gelled oil fracturing treatments performed with prior art chemistry (PAC) are compared to those performed with an enhanced complexation chemistry (ECC).
Novel Dual-Injection System for Water-Shutoff Treatments
Authors: Plahn S. V. , Stevens D. G. , Enkababian P. G. , Anyan S. L. , Feraud J.-P. M.
Published: December 2007

There are numerous water shutoff techniques. One of these is to seal watered-out zones permanently with rigid polymer gelants. This method can be very effective for near-wellbore water flow problems provided the gelant only enters the watered-out interval and does not damage nearby productive pay. Gelant placement can frequently be controlled with mechanical devices, such as packers and bridge plugs; however, gelant may still enter productive pay through flow paths outside the casing. For such cases, mechanical isolation within the well may not suffice, especially if crossflow between zones is high. We discuss a specialized gelant placement technique, referred to as dual-injection, that can be used to address these types of water control problems. Dual injection can be implemented several ways. We discuss some of these, as well as a completely new dual-injection system.
Finite Difference Simulation of Geologically Complex Reservoirs With Tensor Permeabilities
Authors: Lee S. H. , Durlofsky L. J. , Lough M. F. , Chen W. H.
Published: December 2007

The gridblock permeabilities used in reservoir simulation are commonly determined through the upscaling of a fine scale geostatistical reservoir description. Though it is well established that per- meabilities computed in this manner are, in general, full tensor quantities, most finite difference reservoir simulators still treat permeability as a diagonal tensor. In this paper, we implement a capability to handle full tensor permeabilities in a general purpose finite difference simulator and apply this capability to the modeling of several complex geological systems. We formulate a flux con- tinuous approach for the pressure equation by use of a method analogous to that of previous researchers (Edwards and Rogers1; Aavatsmark et al.2), consider methods for upwinding in multiphase flow problems, and additionally discuss some relevant implemen- tation and reservoir characterization issues. The accuracy of the finite difference formulation, assessed through comparisons to an accurate finite element approach, is shown to be generally good, particularly for immiscible displacements in heterogeneous sys- tems. The formulation is then applied to the simulation of upscaled descriptions of several geologically complex reservoirs involving crossbedding and extensive fracturing. The method performs quite well for these systems and is shown to capture the effects of the underlying geology accurately. Finally, the significant errors that can be incurred through inaccurate representation of the full per- meability tensor are demonstrated for several cases.
Injection/Falloff Testing in Heterogeneous Reservoirs
Authors: Banerjee Raj , Thompson L. G. , Reynolds A. C.
Published: December 2007

In this work, we present a new theoretical understanding of pressure data obtained at a water injection well. The theory provides new physical insight into how permeability heterogeneity, saturation gradients, and mechanical skin factor combine to influence the pressure response at the well. Based on the theoretical equations, methods for analyzing injection/falloff pressure data in both homogeneous and radially heterogeneous reservoirs are presented. For homogeneous reservoirs, we present procedures for estimating the mechanical skin factor from injection or falloff pressure data. Our theory provides a procedure for analyzing the pressure re- sponse during the second injection period of a two-rate test. It is shown that the information that can be obtained from a two-rate test is similar to that obtained from a falloff test.
A Review and Analysis of Equipment for Running Electrical Cables Under Pressure
Authors: Cooke A.C.H. , Greer Cecil B. , Scott F.L.
Published: December 2007

Developments in permanent-type well completion techniques have accentuated the need for improved equipment to handle cables under pressure. Existing conventional packoff devices were tested and their dynamic performance established at 200 to 600 psi with electrical conductor cables. A new packoff technique is reported that permits operating stranded cables at moderate running speeds up to pressure as high as 3,000 psi. In the higher pressure ranges a new commercial device is reported for running cables against well pressure as high as 6,000 psi. These new developments open wide the doors to improved well completion practices, resulting in improved well productivity and more precise well control.

Introduction

Field experience with some phases of permanent-type well completions uncover a need for more adequate and simplified means of running conductor cables into wells under pressure. This paper concerns armored electrical cables usually used in service company work, although the findings are equally applicable to other stranded cables.

The construction of a reverse armor electric conductor cable is such that 20 per cent of the cross section area is pore space. The difficulty in sealing this amount of space has dictated, in the past, the use of small diameter cables for even medium pressure work. Early experiments with packing glands used with conductor cables revealed that a complete high-pressure shutoff could only be obtained by filling the pore space within the cable with heavy grease or packing gland pressures, which prohibited or retarded cable movement.

Recently a new concept has developed of handling cables under pressure. Tests have shown that with a stranded cable located in a closely fitting metal sleeve, the flow through and around the cable is not great and can be controlled. This is known as the controlled blow-by principle and its use has opened up a new approach to the stuffing box problem.
NMR as Standard Porosity Tool in the San Jorge Basin: Log Responses and Applications
Authors: Solanet Fernando , Khatchikian Alberto , Breda Eduardo
Published: December 2007

This paper describes our experience with nuclear magnetic resonance (NMR) logs since their introduction in the San Jorge basin in June 1995. To date, more than 400 logs have been run by Western Atlas and Schlumberger using Numar's magnetic resonance imaging tool (MRIL) and combinable magnetic resonance (CMR) tools, respectively, and more than 2,000 zones have been perforated and tested. This has allowed us to characterize the response of the tools in shaly and tuffaceous sands, compare the response of the Numar and Schlumberger tools with each other and with cores, detect the limitations of present tool designs, and relate NMR pore-size distribution and permeability to oil production.
Practical Issues of 4D Seismic Reservoir Monitoring: What an Engineer Needs to Know
Authors: Lumley D. E. , Behrens R. A.
Published: December 2007

Time-lapse three-dimensional (3D) seismic, which geophysicists often abbreviate to four-dimensional (4D) seismic, has the ability to image fluid flow in the interwell volume by repeating a series of 3D seismic surveys over time. Four-dimensional seismic shows great potential in reservoir monitoring and management for mapping bypassed oil, monitoring fluid contacts and injection fronts, identifying pressure compartmentalization, and characterizing the fluid-flow properties of faults. However, many practical issues can complicate the simple underlying concept of a 4D project. We address these practical issues from the perspective of a reservoir engineer on an asset team by asking a series of practical questions and discussing them with examples from several of Chevron's ongoing 4D projects.

We discuss feasibility tests, technical risks, and the cost of doing 4D seismic. A 4D project must pass three critical tests to be successful in a particular reservoir: Is the reservoir rock highly compressible and porous? Is there a large compressibility contrast and sufficient saturation changes over time between the monitored fluids? and Is it possible to obtain high-quality 3D seismic data in the area with clear reservoir images and highly repeatable seismic acquisition? The risks associated with a 4D seismic project include false anomalies caused by artifacts of time-lapse seismic acquisition and processing and the ambiguity of seismic interpretation in trying to relate time-lapse changes in seismic data to changes in saturation, pressure, temperature, or rock properties. The cost of4D seismic can be viewed as a surcharge on anticipated well work and expressed as a cost ratio (seismic/wells), which our analysis shows ranges from 5 to 35% on land, 10 to 50% on marine shelf properties, and 5 to 10% in deepwater fields. Four-dimensional seismic is an emerging technology that holds great promise for reservoir management applications, but the significant practical issues involved can make or break any 4D project and need to be carefully considered.
Predicting Displacement Efficiency From Water-Cut or Gas-Cut Field Data
Authors: Welge H.J.
Published: December 2007

Welge, H.J., SPE-AIME, Petroleum Research Consultants, Inc.

A procedure for predicting oil-displacement efficiency using field data is presented. The method is somewhat simpler than previous methods and is particularly applicable when well are previous methods and is particularly applicable when well are not developed in a regular pattern.

Introduction

A method for predicting the efficiency of oil displacement using field data is presented. The method is particularly applicable when the wells are not developed in a regular pattern, such as alternating rows of injection and producing pattern, such as alternating rows of injection and producing wells, or five-or nine-spot patterns.We assume, nevertheless, that the displacement occurs in a more or less linear manner, as in the portion of an oil field shown in Fig. 1. Here there is a single north-to-south trending row of water injection wells drilled near the center line of the field. The injected water flows mainly toward the east or the west, displacing the oil toward the other (producing) wells. The method presented is somewhat simpler and more straightforward than previous methods.

Procedure Procedure We need, first, an average plot showing fw (the fraction of water in the flowing stream delivered at a well under reservoir conditions) as a function of pore volumes of injection, Wi. To arrive at Wi, we draw a rectangle on the areal map of the oil field (Fig. 1). Two of the opposite sides of this rectangle lie along the direction of average flow of fluids; and these two sides if extended, each pass midway between two injection wells. The other two sides of the rectangle pass through the injection well and nearest producing well, respectively. Thus, this producing well can be considered as withdrawing a "sample" of the fluids flowing past it. The pore volume of the porous body lying under the rectangle, divided into the cumulative volume of water injected into (or through) the rectangle, gives Wi. For Wells I-2 and P-1 in Fig. 1, the fw vs Wi plot shown in Fig. 2 is a reasonable average of the plots for other neighboring wells for which adequate data are available.The scatter of points shown in Fig. 2 is caused partly by the fact that the fw values are obtained from field data by an incremental or derivative process, which tends to magnify any inaccuracies in measurement and any errors caused by shifting streamlines when neighboring wells come on or off stream.To proceed with the displacement prediction, the first step is to arrive at the average water saturation, Sw, in the rectangle that includes Wells I-2 and P-1 (Fig. 1). This average saturation at any throughput will be given by the area above and to the left of the fw vs Wi curve (the smooth curve in Fig. 2) as follows:

Volume of water displaced = .........(1)

where Qi is the total fluid produced at reservoir conditions.

Volume of water injected = .............(2)

Volume of water left inside porous body= .........................(3)

Dividing by the pore volume gives..................(4)

JPT

p. 944
Pompano Through-Flowline System
Authors: Kleinhans J. W. , Cordner J. P.
Published: December 2007

The Pompano field development was done in two phases. The first phase consisted of installing a deep water platform, topsides and export pipelines in 1994. The second phase consisted of installing a 10-well subsea oil production template in 1995 and tying it back to the host platform. The subsea template system, which incorporates through-flowline (TFL) well servicing capability, is discussed in this paper. The subsea system, with emphasis on the TFL aspects is described and costs are provided. A single-phase, steady-state, isothermal circulation model is described. This model was used during predesign to aid simulation of the wide range of TFL system operating conditions that are expected during field life. Actual field experience that has been gained since start up of the subsea system in 1996 demonstrates the value of doing this type of hydraulic modeling. Further TFL-related development work is needed to extend TFL capabilities beyond those applied at Pompano, and these development needs are discussed. Conclusions are provided at the end of the paper.
A Simplified Model for Oil/Water Flow in Vertical and Deviated Wellbores
Authors: Hasan A. R. , Kabir C. S.
Published: December 2007

This paper presents the results of an experimental study and a semitheoretical analysis of two-phase oil/water flow in vertical and deviated systems. The study focuses on water-dominated flow regimes, where the patterns may be termed as bubbly flow, pseudoslug flow, and churn flow. A drift-flux approach is taken to analyze the flow behavior of oil/water systems. For the three flow regimes investigated, the drift velocity of the lighter oil phase is found to be dependent on its in-situ volume fraction in addition to the terminal bubble- or droplet-rise velocity. For flow in both vertical and deviated pipes, we were able to develop a single expression for the drift flux, uow, resulting in a single equation for the in-situ oil fraction, fo, for the three flow regimes studied. We correlated fo with the oil superficial velocity, vos, and the terminal rise velocity, vꝏθ, using the expression, fo=vos/{1.2vm + vꝏθ f(1 — fo)2}. In a deviated pipe, the terminal rise velocity, vꝏθ, is correlated with that in a vertical pipe by =vꝏ/'″ (cosθ)0.5(1 + sinθ)2, for θ <70°. The performance of the proposed method in estimating fo is in good agreement with our measurements. Published data further augment the approach presented here.
Graphical Solution of Imbibition Equations Used To Predict Oil Recovery by Water Influx in Naturally Fractured Reservoirs
Authors: Aguilera Robert
Published: December 2007

Introduction

This article presents graphical solutions to some imbibition equations that describe the recovery of oil from naturally fractured reservoirs with water influx. The equations, presented originally by Aronofsky et al., can be written as

Equation(1)

for the case of a single-model element and

Equation(2)

for the case of a total fractured reservoir where the velocity of advance of the water table is uniform.

In Eqs. 1 and 2, r is recovery at any time t, R is the limit toward which the recovery converges, and X is a constant giving the rate of convergence. By abstract reasoning, these equations have proven to be useful in practical situations. Working the solution by hand, practical situations. Working the solution by hand, however, is difficult because it requires a trial-and-error effort to determine the constants X and R.

The basic assumptions describing the abstract model are (1) the oil production from a small volume, dv, of porous matrix saturated with oil at time zero is a porous matrix saturated with oil at time zero is a continuous monotonic function of time, and it converges to a finite limit, and (2) none of the properties that determine the rate of convergence change sufficiently during the process to affect this rate or the limit. This implies, for example, that variations in wettability and residual oil saturation are not accounted for.

The charts presented in this article were generated to simplify the solution. They are based on work presented by Kern to analyze fouling problems in heat presented by Kern to analyze fouling problems in heat exchangers. (Full-scale graphs are available to the interested reader upon request.)

Notice that the graphical solutions are limited to cases where the continuous monotonic function is of the assumed exponential form. For other cases, a quantitative analysis is not possible.

JPT

P. 1526
Experimental Waterflooding Recoveries Above and Below the Bubble Point
Authors: Bass Daniel M. , Crawford Paul B.
Published: December 2007

Laboratory investigations have been made to study the effect of variations in fluid characteristics, gas saturation, water saturation, and water injection rate on oil recovery by water flooding. Three synthetic gas-saturated crude oils having bubble points of 860, 1,540 and 1,885 psi were used as reservoir fluids. Repeated tests were made in which a sand pack, saturated with water and synthetic oil, was produced by solution gas drive followed by water flooding at various pressure levels. Oil recovery by solution gas drive and subsequent water injection is shown to vary with the pressure and rate at which the water flood is conducted. The pressure at which optimum flooding conditions exist is shown to be a function of the physical characteristics of the reservoir fluid. For the systems studied, increases in oil recoveries of near 10 per cent were obtained by flooding at the most desirable conditions. Variations in initial water saturations gave results similar to those in the literature.

Introduction

Most of the waterflooding studies investigating means of improving present exploitation processes have been conducted at low pressures with little effort to simulate reservoir conditions. Holmgren and Morsel performed a waterflooding study at 300 to 500 psi wherein the gas saturation was created by injecting gas, letting dissolved gas evolve from the oil, and then flushing the core with "live" oil until the desired gas saturation was obtained. Their results show increasing oil recoveries with increasing gas saturations. Data presented by Guerrero and Kennedy, et al, indicate that in some instances waterflooding at approximately 500 psi below the original bubble point results in a lower residual oil saturation than is obtained when water flooding above the bubble point. In their work gas saturations were created by primary depletion. By correcting low pressure flooding data for fluid shrinkage, Dyes found that a maximum oil recovery may be obtained by flooding with initial gas saturations of from 7 to 12 per cent.