bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Pressure Derivative Revisited—Improved Formulations and Applications
Authors: Hosseinpour-Zonoozi N. , Ilk D. , Blasingame T. A. 
Published: December 2007

Abstract
The proposed work provides a new definition of the pressure-derivative function [i.e., the β-derivative function, Δpβd(t)], which is defined as: Δpβd(t)=dln(Δp)dln(t)=1ΔptdΔpdt=Δpd(t)Δp
(Δpd(t) is the "Bourdet" well testing derivative)
This formulation is based on the "power-law" concept (i.e., the derivative of the logarithm of pressure drop with respect to the logarithm of time) — this is not a trivial definition, but rather a definition that provides a unique characterization of "power-law" flow regimes.
The "power-law" flow regimes uniquely defined by the Δpβd(t) function are: [i.e., a constant Δpβd(t) behavior] CaseΔpβd(t)• Wellbore storage domination:1• Reservoir boundaries:— Closed reservoir (circle, rectangle, etc.).1— 2-Parallel faults (large time).1/2— 3-Perpendicular faults (large time).1/2• Fractured wells:— Infinite conductivity vertical fracture.1/2— Finite conductivity vertical fracture.1/4• Horizontal wells:— Formation linear flow.1/2
In addition, the Δpβd(t) function provides unique characteristic responses for cases of dual porosity (naturally-fractured) reservoirs.
The Δpβd(t) function represents a new application of the traditional pressure derivative function, the "power-law" differentia-tion method (i.e., computing the d ln(Δp)/d ln(t) derivative) pro-vides an accurate and consistent mechanism for computing the primary pressure derivative (i.e., the Cartesian derivative, dΔp/dt) as well as the "Bourdet" well testing derivative [i.e., the "semilog" derivative, Δpd(t)=dΔp/d ln(t)]. The Cartesian and semilog derivatives can be extracted directly from the power-law derivative (and vice-versa) using the definition given above.

Objectives
The following objectives are proposed for this work:
Production Data Analysis of Horizontal CBM Wells in Arkoma Basin
Authors: Mutalik P. N. , Magness W. D. 
Published: December 2007

AbstractSince 2001, Williams Production Mid-Continent Company has drilled over 200 horizontal wells in the Hartshorne Coal in the Arkoma Basin in southeastern Oklahoma. The Arkoma basin is an elongate sedimentary basin extending from east-central Oklahoma into Arkansas (Figure 1). The primary zones producing CBM gas in the Arkoma Basin are the Hartshorne sand, and, the Upper Hartshorne Coals, which coalesce into one bed towards the north, and, are the most actively explored gas producing reservoir in the western Arkoma basin.The Hartshorne Coal is a member of the Pennsylvanian Hartshorne Formation, which is a part of the Krebs Group of the Desmoinesian Series (Figure 2). The coals range from high-volatile bituminous to low-volatile bituminous in rank.The Hartshorne Coal encompasses a large area in Haskell, Pittsburg, LeFlore, and, McIntosh counties, and, ranges from 3 ft to 7 ft in thickness. Typical average horizontal drilled length has ranged from 2000 ft to 2500 ft, with the longest well being over 3000 ft. The wells are usually completed with a slotted liner.Unlike CBM wells in other areas of the United States, Hartshorne coal wells are relatively "dry", and, typically produce gas from the first month, with very little water production. This paper presents examples of using analytical techniques for production forecasting, and, reserves estimation for horizontal CBM wells in the Arkoma basin. The production analysis results were integrated with core data, and, material balance calculations, and, indicate recovery factors ranging from 50% to 80% for the Hartshorne CBM wells. The paper also provides a comparison of the performance of horizontal and vertical CBM wells in the basin.In addition, pressure buildup tests were conducted on over 40 horizontal wells, to estimate the reservoir pressure, and, to calculate permeability and skin factor. The paper presents two examples of pressure buildup analysis for Arkoma horizontal CBM wells. The PBU analysis indicated effective permeability in coal of the order of 30 md, which is attributed due to the significant cleating of the Hartshorne coal in the area. The paper includes guidelines for drilling horizontal wells for exploitation of Hartshorne CBM.
Explicit Deconvolution of Wellbore Storage Distorted Well Test Data
Authors: Bahabanian O. , Ilk D. , Hosseinpour-Zonoozi N. , Blasingame T. A. 
Published: December 2007

Abstract
The analysis/interpretation of wellbore storage distorted pressure transient test data remains one of the most significant challenges in well test analysis. Deconvolution (i.e. , the "conversion" of a variable-rate distorted pressure profile into the pressure profile for an equivalent constant rate production sequence) has been in limited use as a "conversion" mechanism for the last 25 years. Unfortunately, standard deconvolution techniques require accu-rate measurements of flowrate and pressure — at downhole (or sandface) conditions. While accurate pressure measurements are commonplace, the measurement of sandface flowrates is rare, essentially non- existent in practice.
As such, the "deconvolution" of wellbore storage distorted pres-sure test data is problematic — in theory, this process is possible, but in practice, without accurate measurements of flowrates, this process can not be employed. In this work we provide explicit (direct) deconvolution of wellbore storage distorted pressure test data using only those pressure data.
The value of this work is that we provide explicit tools for the analysis of wellbore storage distorted pressure data — specifi- cally, we utilize the following techniques: — Russell method (1965) (very approximate approach).— "Beta" deconvolution (1950s and 1980s).— "Material Balance" deconvolution (1990s).
Each method has been validated using both synthetic data and literature field cases and each method should be considered valid for practical applications (the Russell method was not used).
Our primary technical contribution in this work is the adaptation of various deconvolution methods for the explicit analysis of an arbitrary set of pressure transient test data which are distorted by wellbore storage — without the requirement of having measured sandface flowrates.
Rate Allocation Using Permanent Downhole Pressures
Authors: McCracken M. , Chorneyko D. 
Published: December 2007

Abstract
A common industry practice is to commingle production, either downhole or at the surface. Where multiple layers are present in a reservoir, the most economical development plans often involve commingling the production of all the layers. Commingling production is also cost effective in multiple well scenarios such as on a platform. In these situations, it is challenging to determine the individual flow rates from each layer or well. One operating practice is to isolate each layer or well and determine what fraction of the total production can be attributed to each entity. This fraction is then used to allocate production until individual entity rates can be measured again. Rate allocation methods are often required by regulatory agencies and can require expensive well interventions in terms of delayed production and complex completions such as ‘smart’ wells.
Today, many wells are instrumented with permanent downhole pressure gauges which are employed for performance prediction, production optimization, and other reservoir management tasks. In this paper, the use of downhole pressure data is extended to rate allocation. In terms of Darcy's Law, there is a physical link between pressure gradients and flow rates. ExxonMobil has developed a methodology to calculate bottomhole flow rates for each layer or well based on total production and the bottomhole pressure for each layer or well. This paper describes the issues involved, outlines the workflow to address the allocation, specifies the calculations involved, and uses two field examples to illustrate the method. This method shows promise for more accurately allocating production and reducing the required number of well interventions.
Field Experience in Multiphase Gas-Well Testing: The Benefit of the Combination of Venturi and Gamma Ray Fraction Meter
Authors: Pinguet B. G. , Roux G. , Hopman N. 
Published: December 2007

Abstract
Using multiphase flowmeters in field operations has now become a widely accepted practice especially in the range of Gas Volume Fraction (GVF) of 0 to 85%. There is still some doubt about the performance of this type of device especially in the High (92-96%) or Very High GVF (96-98%) ranges. Most of the purchasers put a cut off in the GVF range of 85- 92% following the type of technology. These criteria are often based on past experience or special cases, which could be several years old. A split in terms of naming is even commonly accepted in the multiphase business between Multiphase Flow Meter and Wet Gas Meter.
With the recent dedicated Gas Mode developed by Schlumberger, it is now possible to test both gas and oil wells with the same hardware. The focus put in the past few years on a combination of robust and simple measurements (Venturi and gamma ray) in multiphase flow-metering solutions for any type of well based on the advantages and benefits of the industry recognized Vx* Technology.
In this paper, we will review the benefit of the combination of Venturi and gamma ray fraction meter and its application to gas well testing.
Today, the use of the entire information of a gamma ray spectrum gamma ray (more than 2 rays) allows a real-time or an a posteriori quality control and improvement of the overall performance of the meter in any type of conditions. This statement will be presented through a campaign of tests done in South America. First of all, we will show how the entire information of a gamma ray spectrum permits a quality control in real time, and allows tracking of fluid composition change over time. Then we will focus on high producing gas wells clean-up that have been successfully tested using the Vx technology in Gas Mode in 2005. Exceptional results against conventional test separator have been presented in previous paper (Ref [10]) with a maximum error of 2-3% for the gas.
The current paper will also put a special emphasis on the salinity change.
Flow-Assurance Aspects of Subsea Systems Design for Production of Waxy Crude Oils
Authors: Alboudwarej H. , Huo Z. , Kempton E. 
Published: December 2007

Abstract
Development of deep offshore fields is costly. As such, accurate information is required before a decision can be made on the feasibility of prospect development. Such sets of information include the reservoir fluid characterization and flow assurance data. The subject of this paper is to demonstrate the importance of accurate and representative fluid characterization and resulting flow assurance data on optimum facility and production method design for development of offshore fields.
In this study, fluid characteristics and flow assurance aspects of a live waxy crude oil from offshore West Africa is investigated. Experimental work included determination of the wax appearance temperature (WAT) and rheological studies which included pour point, gel strength, and shear-dependent viscosity measurements under both dead and live oil conditions. The wax deposition tendency of the dead crude oil was also investigated. The experimental data were used for a case study to demonstrate the effect of live oil data versus dead oil data on the subsea system design and operating procedures.
The case study indicated if dead oil data was utilized, the subsea system design and operating procedures would be considerably more conservative than if live oil data was the basis of the design. For a marginal field, these differences could be the difference between an economical field and an abandoned field.
Nonlinear Simulation of Thermo-Viscous Fingering in Nonisothermal Miscible Displacements in Porous Media
Authors: Islam M. N. , Azaiez J. 
Published: December 2007

Abstract
Full nonlinear simulation of the thermo-viscous flow is carried out to study the thermo-viscous fingering in non-isothermal miscible displacements in two-dimensional rectilinear porous media. The problem is formulated using momentum balance equation in the form of Darcy's law, and volume-averaged mass and energy balance equations in the form of convective-diffusion equations. Exponential dependence of viscosity on concentration and temperature is used. With the use of vorticity-streamfunction formulation and periodic boundary conditions, the coupled system of nonlinear equations is solved conveniently using highly accurate pseudo-spectral method. The transient development of thermo-viscous instability is studied for different values of solutal (PeC) and thermal (PeT) Peclet numbers, Lewis number (Le) and the parameters representing the concentration (βC) and temperature (βT) dependence of viscosity. In Hele-Shaw flow, the effects of βC and βT are found to be additive when Le is unity, while at smaller values of Le the frontal instability is further enhanced. At practically large values of Le, the fluid and the thermal fronts evolve differently, with the fluid front being more unstable. The reduction in instability on the thermal front is found to be due to the enhancement of the thermal dispersion in such flow. Finally, it has been noticed that at large values of Le, the instability in the thermo-viscous flow is dominated by the viscosity contrast due to the variation in concentration across the fluid front, which was also reported in earlier literature.
Uinta Basin Single-Well Model To Optimize Tight Gas Completions
Authors: Cherian B. , Aly A. , Denoo S. , Maschio L. , Sobernheim D. , Longwell J. 
Published: December 2007

Abstract
In this paper, we will present an integrated single well modeling (SWM) technique to predict reservoir and completion performance for a Uinta basin development program. This technique has proven to be vital in the economic success of wells in the Uinta Basin. The integrated SWM involves the development of a petrophysical and a mechanical stress model calibrated from offset nearby wells to match well production and fracturing treatments response.
The SWM is coupled with the development of NPV optimization models for each well. Tools for the validation of the SWM such as production logs, pressure measurements, and formation micro-imager (FMI) have not only been crucial in model validation, but also in order to: Evaluate production contributions based on backpressureEvaluate drainage area (from multiple production logs)Understand geological setting and production mechanismDetect scaling problems and optimize treatment solutionsUnderstand limited entryIdentify water producing zonesDevelop commingling production strategy
Since a typical completion in the Uinta Basin may contain multiple producing sands (as many as 30), optimizing the completion strategy may be a challenging task. Completions are designed to optimize the production from each stimulation stage. This is achieved by calibrating the pre-stimulation injection tests on these stages using theoretical fracturing models such as pseudo-3D (P3D). Pressure history matching of fracturing data and production data provides the feedback information necessary to validate the models and improve predictability, thus improving the quality of decisions made subsequently. This process is continuous and models are updated or changed according to the geological and petrophysical setting.
After the wells are completed, the use of production logs in stacked pay reservoirs enables the use of rate-&-pressure transient analysis and history matching techniques to evaluate fracture and reservoir properties. The use of these tools early in the drilling program has resulted in changes to completion and production strategies that have resulted in significant cost saving via modifications to fluid technology, proppant selection, proppant flowback control methods, commingling strategies, scale inhibition and drilling locations. Over all, the application of appropriate evaluation tools based on geological setting and appropriate information gathering has resulted in production increases of up to 30% above the previous baseline, with significant improvement in well economics.
Automatic Concurrent Water Collection (CWC) System for Unloading Gas Wells
Authors: Khoshnevis B. , Rastegar Moghadam R. , Ershaghi I. , Larbi K. , Villagran V. 
Published: December 2007

Abstract
Several methods for unloading water from gas wells have been used in the industry. These methods commonly have a combination of the following characteristics: a) they use external energy, b) they use consumables, and c) they restrict gas production. This paper presents a new approach to water unloading that does not restrict or interrupt gas production, can operate without external energy, and uses no consumables. Physical and software simulators have been developed to demonstrate the feasibility of the new approach and to configure the approach for various well characteristics.
Consistent Downscaling of Seismic Inversions to Cornerpoint Flow Models
Authors: Kalla Subhash , White Christopher D. , Gunning James G. , Glinsky Michael E. 
Published: December 2007

Abstract
Reservoir simulation models are constructed from sparse well data, dense seismic data, and using geologic concepts to constrain stratigraphy and property variations. Because of the sparseness of well data, stochastically inverted seismic data offer important constraints on reservoir geometry and average properties. Although seismic data are densely distributed, they are uninformative about meter-scale features. Conversely, well data reveal fine-scale features but cannot specify intrawell geometry. To build a consistent model, conceptual stacking and facies models must be constrained by well and seismic data. Stochastic ensembles of geomodels are used to capture variability associated with seismic downscaling, lateral variability and conceptual models. The resulting geomodels must be gridded for flow simulation using methods that describe stratal architecture flexibly and efficiently.
In this paper, geomodels integrate stochastic seismic inversion results (for means and variances of "packages" of meter-scale beds), geologic modeling (for a framework and priors), rock physics (to relate seismic to flow properties), and geostatistics (for spatially correlated variability). These elements are combined in a Bayesian framework. The proposed workflow produces models with plausible bedding geometries, where each geomodel agrees with seismic data to the level consistent with the signal-to-noise ratio of the inversion. An ensemble of subseismic models estimates the means and variances of properties throughout the flow simulation grid.
Grid geometries with possible pinchouts can be simulated using auxiliary variables in a Markov Chain Monte Carlo (MCMC) method. Efficient implementations of this method require a posterior covariance matrix for layer thicknesses. Under assumptions that are not too restrictive, the inverse of the posterior covariance matrix can be approximated as a Toeplitz matrix, which makes the MCMC calculations efficient. The proposed method is validated and examined using two-layer examples. Convergence is demonstrated for a synthetic threedimensional, 10,000 trace, 10 layer cornerpoint model. Performance is acceptable (305 s on a 2 GHz Pentium-M processor).
The Bayesian framework introduces plausible subseismic features into flow models, whilst avoiding overconstraining to seismic data, well data, or the conceptual geologic model. The methods outlined in this paper for honoring probabilistic constraints on total thickness are general, and need not be confined to thickness data obtained from seismic inversion: any spatially dense estimates of total thickness and its variance can be used, or the truncated geostatistical model could also be used without any dense constraints.
Stimulation in Asia Pacific Region—Challenges and Opportunities
Authors: Jin L. , Seah M. 
Published: December 2007

AbstractOil and gas assets in Shell Asia Pacific region formulate challenges and opportunities for improving well productivity through stimulation. Major factors limiting the activity in the past include: Various types of reservoirsMixed success rateOperational difficultiesCost structure: coil tubing cost overruns the overall stimulation costWeather conditions.Stimulation activities have been picked up since 2004 with encouraging successes. Among them are successful hydraulic fracture stimulation in STOS and sandstone matrix acid stimulation campaigns in Brunei and Malaysia. Recently, stimulation in carbonate gas reservoirs brought new successes.This paper discusses what have been done to identify and capture opportunities through collaborated efforts. Best practices and learnings leading to the success will be shared.Some of the high lights of the practices include: Opportunity identification and detailed designDetailed well-by-well review for first round candidate selection.Fundamental data collection is vital. A data management system allows quick access to well production history data.Design tool (software) for final candidate selection, fluid system selection, and job design.QA/QC and compatibility tests aiming to obtain high success rate.Combine equipment (self-raising rig and barge) with pumping procedure (coiled tubing and bull-heading) to best-fit individual well condition.Close cooperation (Well services, Production technologists, Service providers, etc.) during implementation.Game change in acid stimulating carbonate horizontal gas wells.Hydraulic fracturing in STOS has significantly improved gas production. Sandstone matrix acidizing campaigns in 2004 brought 9000 boepd of gain in assets in Brunei and Malaysia with high success rate (no failure was recorded).Confidence level of stimulation in Shell Asia Pacific region has been elevated. Lessons learnt and best practices established will be passed to future campaign. Stimulation is still a good means for increasing well productivity to get more oil at this high oil price time, but it has to be carried our properly.Although some success was achieved, current infrastructure for stimulation in the region still needs to be improved.
Seismically Driven Reservoir Characterization Using an Innovative Integrated Approach: Syd Arne Field
Authors: Christensen S. A. , Dalgaard T. E. , Rosendal A. , Christensen J. W. , Robinson G. , Zellou A. M. , Royer T. 
Published: December 2007

Abstract
This paper presents an innovative integrated workflow applied to the characterization of a fractured chalk reservoir in the Danish North Sea. The methodology uses simultaneous integration of geophysical, geological and engineering data to produce an improved reservoir description. Integrating dynamic flow data with the geophysical and geologic information in 3D, reservoir properties porosity and effective permeability are generated using artificial intelligence tools. The strength of this technique lies in the fact that property modeling is not constrained to match upscaled well data and consequently these data serve to validate the outcome.
This workflow builds upon a methodology that has been used successfully for the characterization of fracture distribution. The technique has been extended to include the generation of seismically derived models of porosity and matrix permeability.The objective of the approach is to improve the ability to capture the heterogeneity of key reservoir properties, and thus use the resulting reservoir model to both provide improved predictive ability and identify previously undiscovered development opportunities. The application and outcome of this integrated workflow to the Syd Arne field is presented in this paper.