bluuebunny/crossref_metadata_2025_split huggingface dataset:
Acid Fracturing of Gas Wells Using an Acid Precursor in the Form of Solid Beads: Lessons Learned From First Field Application
Authors: Nasr-El-Din H. A. , Al-Zahrani A. A. , Garzon F. O. , Giraldo C. A. F. , Al-Hakami I. M. , Al-Marri H. M. 
Published: December 2007

AbstractAcid fracturing treatments are commonly used to enhance the productivity of carbonate formations with low permeability zones. Various forms of HCl acid are used to create deep etched fractures. However, HCl reacts very fast with the carbonate rocks and unless retarded, will produce a fracture with low conductivity. In addition, concentrated HCl-based acids are very corrosive to well tubulars, especially at high temperatures. To address problems associated with concentrated acids, various retarded acids were introduced. Organic acids were also used in some cases. These acid systems were successfully used to acid fracture several wells in a deep gas reservoir in Saudi Arabia. Field data, however, indicated that there is a need to create deeper and more conductive fractures. To achieve this goal, it was decided to conduct a field trial with a newly developed acid system.The new acid system is an ester of an organic acid in the form of solid beads. The ester reacts with water (hydrolyzes) at bottom temperature and produces an organic acid. The organic acid then reacts with carbonate minerals and etches the surface of the fracture. The system was thoroughly examined in the lab and showed promising results.The treatment was conducted in the field without encountering operational problems. After successful placement of the solids in the fracture, the well was shut-in for 24 hours to give ample time for the ester to hydrolyze and for the generated acid to react with the formation rock. The well was allowed to flow and samples of the fluids produced were collected to understand chemical reactions that occurred during the treatment. The treatment has resulted in a slight increase in gas production. And as a result, the well was matrix acidized using 28 wt% HCl and responded very well to the matrix treatment.This paper will discuss major reactions that occurred during this treatment, and how they impacted well response. Lessons learned and recommendations to improve the results of this new acid system will be discussed in detail.
The First Offshore Use of an Ultrahigh-Speed Drillstring Telemetry Network Involving a Full LWD Logging Suite and Rotary-Steerable Drilling System
Authors: Wolter H. , Gjerding K. , Reeves M. , Hernandez M. , Macpherson J. , Heisig G. , Zaeper Ralf 
Published: December 2007

Abstract
Drill string telemetry network technology allowing reliable data transmission at speeds up to 57,600 bits per second has been utilized in many land based drilling applications.
The drill string telemetry network incorporates a high-strength data cable that runs the length of each tubular joint. The cable terminates at inductive coils that are installed in the secondary torque shoulder of each connection. As the drill string is assembled, the inductive coils in adjoining tubulars are brought close together allowing data to flow across the connection. The network signal is boosted occasionally by repeater subs, which also provide locations for along-string temperature measurements. The technology offers robust, reliable operation and is virtually transparent to standard rig procedures.
In 2007, the Troll field in Norway saw the first commercial deployment of this technology into a complex offshore multilateral drilling project.
This paper details the lessons learned and value derived from the use of an ultra-high speed drill string telemetry network and compatible rotary steering, drilling dynamics and advanced formation evaluation measurement tools while drilling multiple laterals of an extended reach horizontal well from a semi-submersible drilling rig.
Of particular focus will be discussion of the specific value gained from: real-time analysis of high resolution dynamics and inclination measurements to instantly manage the drilling transition between relatively unconsolidated sands with imbedded hard calcite-cemented stringers; instantaneous network-enabled surface control of rotary steerable tools to eliminate non-productive time and improve directional control; real-time transmission and interpretation of high-volume, memory quality formation evaluation measurements to improve geological well placement; and non-productive time elimination resulting from the availability of full telemetry redundancy.
The paper includes comment and perspective from the Troll field operator regarding the immediate value and likely future utilization of telemetry drill string technology.
Use of Spoolable Reinforced Composite (SRC) Pipe for Transfer of Low Pressure Oil & Gas in BP Pakistan
Authors: Khan Asad Ali. , Naeem Muhammad , Asif Muhammad 
Published: December 2007

ABSTRACT
BP Pakistan has been laying cross-country pipelines to produce oil and gas in the Badin concession for the last 20 years, and has gained considerable experience with conventional carbon steel material. The average time required to lay a 4" diameter × 5000 ft long steel pipeline has been around 4 weeks. There was a desire to reduce this time to improve put-on-production (POP) time. Other factors driving us to think out of the box were corrosion, high operating and life cycle cost etc.
A project consisting of laying 4"-1500 psig × 5000 ft Spoolable Reinforced Composite (SRC) pipeline from wellhead to facility was initiated in consultation with BP Exploration & Production Technology Group (EPTG). EPTG was actively involved in the development of this new technology in the wider BP world, and this was seen as an opportunity to test the material in Pakistan. Testing of the material for potential use in high-pressure (HP) gas was also envisaged. In order to ensure rigorous testing of new material and technology, one of the toughest construction location (high water table, collapsing trench, three major crossings, a number of minor crossings, etc.) was selected. Since most of the potential risks to delivery were evaluated upfront, the result was a record laying time of 0.5 km / hr. The project was completed with great success and learnings for the use of this technology in future, and to share with others who choose to use the same material and technology.
This paper provides a brief overview of this new material, its physical properties, potential use, characteristics, advantages over conventional carbon steel and installation experience at BP Pakistan and recommendations for future utilization in oil and gas industry.
Investigation of Methods to Improve Utica Shale Hydraulic Fracturing in the Appalachian Basin
Authors: Paktinat J. , Pinkhouse J. A. , Fontaine J. , Lash G. G. , Penny G. S. 
Published: December 2007

Abstract
The primary purpose of stimulating fractured shale reservoirs is the extension of the drainage radius via creation of a long fracture sand pack that interconnects with natural fractures thereby establishing a flow channel network to the wellbore. However, there is limited understanding of a successful method capable of stimulating Utica Shale reservoirs. Indeed, most attempts to date have yielded undesirable results. This could be due to several factors, including formation composition, entry pressure, and premature pad fluid leak-off. Furthermore, stimulation of Utica shale reservoirs with acid alone has not been successful. This treatment method leads to a fracture length and drainage radius less than expected resulting in poor well productivity.
In this work, geological data is first examined for the reservoir. Laboratory data are then presented to address the unique mineralogy and mechanical properties of the Utica shale. The high percentage of acid soluble carbonate and dolomite suggests an acid treatment to lower entry pressures. This treatment can be the main stimulation of a vertical or horizontal well since natural fractures are present, or the acid breakdown can precede a gelled acid or proppant laden water frac or crosslinked fracturing fluid treatment. Experimental results reveal the impact of clays, potential generation of fines both siliceous and organic, acid solubility, low temperature biological activity, potential for scale generation and the prevalent problem of recovery of injected fluids. Acid solubility is presented vs. time and acid strength. Conductivity data is presented for gas fracs, matrix acidizing and proppant fracturing of the shale. The adsorption, as well as the regained relative permeability to gas is examined vs surfactant type to allow the selection of an additive package that will optimize fluid recovery and improve relative permeability to gas. Information obtained from this study can be used to optimize fracturing treatments of Utica shale reservoirs in the Appalachian Basin.
Accurate Calculation of Hydrocarbon Saturation Based on Log-Data in Complex Carbonate Reservoirs in the Middle-East
Authors: Obeida T. A. , Al-Jenaibi F. , Rassas S. , Serag Eldin S. 
Published: December 2007

Abstract
Generating saturation functions (capillary pressure or J-functions), to initialize complex carbonate reservoir, always presents challenge to Petrophysicists and reservoir engineers, especially with no SCAL data available or any existing rock properties trends such as porosity-permeability relationship which are used to assign saturation function in 3D models. The proposed method requires initial water saturation (Swi) distribution in 3D model in hand (first stage) and then the Swi distribution recalculated more accurately (second stage) using group of capillary pressure (Pc) curves based on Swi intervals. Calculating Swi distribution in two stages should not impose any limitations since in the first stage Swi distribution can be estimated by many ways such as J-functions (4), group of Pc curves based on porosity intervals (part of this work). Otherwise, it may be estimated by any girding software which uses Swi log-data, but this method is not recommended since the software would give erroneous estimation of Swi in the areas of no well control such as in the transition zone area.
The proposed method calculates the Swi distribution in two stages, first the Swi calculated by Pc curves based on porosity rages, then in the second stage the Swi recalculated using group of Pcs based on water saturation ranges.
A script file was written to differentiate between these regions and assign saturation numbers (SATNUMs) for each saturation region which used in the simulator to initialize the dynamic model. Shuaiba reservoir is presented as study case here to demonstrate the capability of the proposed method. The proposed procedure can be to initialize huge complex carbonate reservoir such as Shuaiba formation in the United Arab Emirates.
The initial water saturation profile from log data matched the water saturation calculated by the dynamic model in 90% of the wells (more than 100 wells at initial water saturation).
The proposed procedure eliminates the tedious efforts to find rock property trends such as porosity-permeability correlations, which in many carbonate reservoirs may not exit, in order to assign a saturation function for each porosity/permeability range(s).
The difference in initial oil in place (STOOIP) calculations between the static model (40 million cells) and the dynamic model (2.7 million cells) is less than 2 percent. It can be used also in many heterogeneous reservoirs to reduce the uncertainty in STOOIP and thus reserves estimations.
The Evolution of Automation in Drilling
Authors: Eustes Alfred W. 
Published: December 2007

Abstract
This paper has been written for the keynote speech to be given in the "Drilling Automation – Where Are The Game Changers?" plenary session for the 2007 SPE Annual Technical Conference and Exhibition in Anaheim, California. The paper covers the evolution of drilling mechanization and automation from the mid-nineteenth century to today. In the history of drilling, there have many aspects of drilling mechanization and automation that have been investigated, machines designed and built, and operations implemented with varying levels of success and many failures. These aspects include drilling fluid systems, cementing operations, downhole automation, and the rig floor. Because drilling mechanization and automation history has been centered on the rig floor and related surface operations, the focus of this paper is on the rig floor for drilling operations such as rate of penetration, rotary systems, rig floor mechanization and automation, and entire drilling rig automation.
Viscoelastic Surfactants: A New Horizon in Fracturing Fluids for Pennsylvania
Authors: Leitzell Jeffrey R. 
Published: December 2007

Abstract
The Upper Devonian play within Pennsylvania has been the predominant focus of most operators for many years. These sandstone and siltstone formations are regularly hydraulically fractured with a variety of fluids ranging from high concentration crosslinks, linear gels, polyacrylamide slick waters and even treated fresh water. These fluids, although economical, lack quality and can cause severe damage during the stimulation process. Whether it is leaving behind heavy residual damage or not supplying enough viscosity to carry proppant deep into the created fracture, these fluids do not offer the advantages of an all-inclusive system.
Recently, with the development of visco-elastic surfactants (VES's), a standalone, total package fluid is available at an economical cost. VES's offer high quality with no polymers, giving us a completely clean fluid without residual damage. They can be designed to supply a wide range of viscosities with excellent carrying properties to help ensure optimal proppant placement. With the fluid being surfactant based it is a good foaming agent, which provides exceptional water recovery and strong flowbacks.
Best of all, these fluids are all-inclusive, removing the need for additional additives. It consists of one on-the-fly additive that is compatible with extremely poor quality water that may have been reused. There is no need for additional clay controls, biocides, surfactants or iron controls, but in extreme cases, their additions do not create any compatibility issues. This allows VES's to deliver a high quality system at a competitive price.
This paper will take an in depth look at visco-elastic surfactants and their current applications in the Upper Devonian throughout Pennsylvania. It will highlight the treatment design, operational execution and production results from a variety of wells during the initial application of VES fluids.
Type Curve-Based Production Prediction Tool for CBM Prospects
Authors: Aminian K. , Ameri S. , Bhavsar Bhavsar 
Published: December 2007

Abstract
The complex nature of gas production from CBM reservoirs requires significantly more reservoir properties than conventional reservoirs. Parametric studies are often conducted to evaluate the impact of the reservoir parameters on recovery factor, well performance, and future revenues. To conduct parametric studies, the production behavior must be predicted for ranges of various reservoir parameters. In order to incorporate the unique flow and storage characteristics of CBM reservoirs, it necessary to utilize complicated and expensive reservoir models to predict production performance of the CBM reservoirs. Therefore, a simple yet reliable tool is needed for predicting production behavior of CBM reservoir. The CBM Production Predication Tool developed in this study is a quick and reliable tool that can assist the typical gas producers in evaluation of CBM prospects. The tool utilizes the previously developed CBM Production Type Curves as a foundation to predict the production performance. The results can be used to evaluate the economic feasibility and to maximize potential recovery. To simplify the application of type curves for parametric studies a software package with a graphical user interface using Visual Basic programming language has been developed. The input requirements are simple and straight forward. The output is provided both in graphical and tabulated forms which can be exported into spreadsheet for further analysis by the user.
A Simple and Reliable Method for Gas Well Deliverability Determination
Authors: Aminian K. , Ameri S. , Yussefabad A. G. 
Published: December 2007

Abstract
Multi-rate tests generally provide accurate values for gas reservoir formation parameters and deliverability equation coefficients. This type of results enables the engineer to make proper decisions on whether remedial work is required and the potential improvement that can be achieved. The multi-rate tests, such as isochronal or modified isochronal tests, are however cumbersome to conduct due to need for achieving stabilization or lengthy shut-in periods.
The goal of this study has been to develop a simple and reliable method for gas well deliverability determination based on a single rate build-up or fall-off test. Traditionally, single rate tests have been analyzed using empirical backpressure equation using an average value for the exponent (n). Such approximations often provide inaccurate results and do not reveal any information regarding the conditions of the well. Alternatively, single rate tests can be analyzed using theoretical transient gas flow solutions. However, to accurately estimate mechanical skin factor and the deliverability equation coefficients from a single rate test, turbulence factor, β, must be available. There are numerous correlations in the literature for estimating β. These correlations do not provide unique results and calculated skin factor can range widely as a result.
This study introduces the concept of the reservoir-specific β-factor. The methodology for developing a correlation for β factor using multi-rate tests has been developed. Once the β-factor correlation for a reservoir is established, there would be no need for additional multi-rate tests and single rate can be analyzed to provide accurate estimates of mechanical skin factor and deliverability equation coefficients. The accuracy of the proposed methodology has been verified through application in two separate reservoirs in the Appalachian Basin.
Improved Fracturing Technology for Coalbed Methane Gas Wells in Western Pennsylvania Increases Gas Production Over Offset and Historic Wells in Mount Pleasant CBM Field
Authors: Snyder S. G. , Jockel D. W. , Lopez A. W. 
Published: December 2007

Abstract
Coalbed methane (CBM) drilling has been occurring in the Mount Pleasant, Westmoreland County, Pennsylvania area for about a decade, with various fracturing techniques applied in these CBM wells using conventional gas well fracture methods. However, production has been response-limited either due to incomplete placement of fracturing designs and/or because these older conventional gas well fracturing designs were not effective for these CBM wells.
Due to the poor nature of the production in these coal seams, it was determined to look more closely at the fracturing techniques and apply newer technologies designed specifically for CBM well fracturing. The objective of this review was to make future drilling of the CBM wells in this area economically feasible. This paper will discuss specifics of the coalbed field, fracture designs applied in the past and in the present, fracturing job design considerations, and chemical attributes for the fracturing job.
Most of the historic fracs placed on these wells used a linear gel guar system, low sand concentrations, low sand volumes, larger proppant size, and relied on high pump rates to put the sand away. More recent frac designs were developed to utilize a hybrid crosslinked fluid system, higher sand concentrations, higher sand volumes, and a lower pump rate. Also, chemicals designed more specifically for CBM wells are included in the redesigned test wells.
Finally, we will discuss gas production with the historic fractures that were placed on these wells in the past along with several current wells in the field that used a different design. We will then compare the gas production from these data sets to the gas production for the wells in the field that were fractured by applying the new fracturing technologies. By comparison of the data sets, this paper will demonstrate that the new fracturing technologies applied to this CBM field have resulted in significantly improved gas production for the perator.
A Deconvolution Method Based on Cumulative Production for Continuously Measured Flowrate and Pressure Data
Authors: Ilk D. , Valkó P. P. , Blasingame T. A. 
Published: December 2007

Abstract
This work presents a new methodology for the analysis of permanent downhole gauge and production data based on the deconvolution of cumulative production and bottomhole pressure measurements.
In this work we show that the cumulative production is a convolution of pressure drop (as if the well were producing at a series of constant flowing bottomhole pressures) and flowrates (as if the well were producing at a constant pressure throughout the production history). We then employ our modified B-spline based deconvolution algorithm which, in this work, is based on constant stepwise pressures. We use analytical integration of the B-splines, weighted least squares and regu-larization to obtain the constant-pressure rate response function and to estimate the initial pressure. The Laplace transformation is not required in this work.
We have validated this approach thoroughly using a synthetic case. We have applied this methodology to various field example cases consisting of both high and low frequency production data. The results indicate that the new method is very efficient in recovering the constant-pressure rate response function in cases where rates are controlled by series of constant flowing bottomhole pressures. We also provide a procedure to check the correlation between pressure and rate measurements by the joint use of two deconvolution methods (SPE 95571 and this work).
Dynamic Rock Types for Generating Reliable and Consistent Saturation Functions for Simulation Models
Authors: Ghedan Shawket G. 
Published: December 2007

Abstract
In reservoir characterization studies, static reservoir rock types, SRRTs, are utilized to guide the modeling of reservoir petrophysical properties in static geological models. However, since the reservoir dynamic properties are not considered in the static rock typing schemes, the SRRTs should not be used - as being practiced now – to guide the distribution of the reservoir multiphase dynamic properties of capillary pressure, Pc, and relative permeability, Kr, curves to the cells of dynamic simulation models.
Considering the rock attributes that goes into any SRRTs scheme and assuming identical interfacial tension between the different reservoir fluids, this paper suggests that the dynamic reservoir rock types, DRRTs, would only be a function of wettability for any SRRT. Thus by imposing wettability on the SRRTs, reservoir engineers should be able to generate the DRRTs, the proper guide for generating and distributing Pc and Kr curves for simulation models.
This technique is applied for building the simulation model of a major carbonate oil reservoir. The gradual change of reservoir wettability from oil wet to water wet dictated the generation of many DRRTs for any SRRT, each defines that SRRT at a different reservoir level between the top and the upper limit of the transition zone.
Available experimental Pc and Kr data, acquired for only few SRRTs, were utilized to develop correlations to determine the saturation and Kr endpoints of the Kr curves. The connate water saturation, Swc, of any DRRT is picked from the Pc curve of the parent SRRT at that DRRT reservoir level. Swc correlated with the residual oil saturation, Sorw. Sorw is in turn used to establish the maximum water Kr point of Krwmax. Oil Kr maximum point, Kromax, is assumed to be 1. Furthermore, the shape of the different Kr curves would be devised by picking the corresponding Corey exponents as they are correlated with wettability for any SRRT. The consistently derived sets of Kr curves helped build a very well initialized and history matched simulation model.