bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drawdown Guidelines for Sand Control Completions
Authors: Tiffin David L. , Stein Michael H. , Wang Xiuli 
Published: December 2007

Abstract
This paper details a method for determining maximum safe production rates for sand control wells. This method was developed from a thorough compilation of data from over 200 sand control wells. As a result of this analysis, a simple function of flux (fluid flow per unit area of screen) proved very reliable at separating wells operating safely from those resulting in damaged screens or unacceptable amounts of produced sand.
Prior to this work, BP (and the industry) used a variety of methods to attempt to optimize production from sand control wells. Most of these prior methods use pressure drop across the completion and were loosely based on experience and rules of thumb. It is shown that these pressure based draw down limits are either ineffective for managing risk of well integrity or unnecessarily constrain well productivity.
We are currently using this new flux-based approach as a basis of design for new wells and to open existing wells to a maximum safe operating production rate. Significant production addition has been added without any well failures as a result of opening up these artificially constrained wells. We furthermore anticipate preventing future well failures caused by operating at too high a rate. Earlier in 2002, two BP-operated sand control wells suffered apparent screen erosion failures; both operating at low drawdowns and safe limits using old guidelines, but at flux rates exceeding these new proposed guidelines.
Use of High-Strength Alloys and Elastomers in Heavy Completion Brines
Authors: Silverman Seth A. , Bhavsar Rashmi , Edwards Charles , Virally Stephane , Foxenberg William 
Published: December 2007

Abstract
Recent field experiences have shown that stress corrosion cracking (SCC) failures can occur when high-strength, low-alloy steels and stainless steels are exposed to heavy completion brines. SCC of super 13Cr and duplex stainless steels has also been reported in lighter CaCl2 brines that have sulfur-containing additives. Modifications of fluid composition with particular attention to additive selection and careful materials selection are required to prevent field failures of completion and service-tool hardware.
The authors have performed laboratory testing to understand the interactions of completion brines that contain zinc bromide (ZnBr2) with the common metallurgical alloys used in service tools, workstring materials, and other permanent downhole equipment. There has been little published work on environmental cracking of common engineering alloys in corrosive ZnBr2 blends. Recent case histories with high-strength downhole service-tool components are described and solutions are proposed to address exposures to heavy brines. Selection of elastomers and seals for use in these environments also requires consideration of the fluid type and additive package.
As a result of their testing, the authors have developed internal guidelines that require the use of severe service equipment for brines with densities higher than 17.0 lbm/gal in temperatures over 275ºF. If thiocyanate additives are required for corrosion control, careful control of the brine blend, pH modification, and/or the use of organic sulfide scavengers are recommended.
Acid Fracturing HT/HP Gas Wells Using a Novel Surfactant Based Fluid System
Authors: Nasr-El-Din Hisham A. , Al-Driweesh Saad , Al-Muntasheri Ghaithan A. , Marcinew Richard , Daniels John , Samuel Mathew 
Published: December 2007

Abstract
During acid fracturing of carbonate reservoirs, the acid dissolves the rock, creating wormholes which increase fluid loss. Excessive fluid loss lowers the net pressure in the fracture limiting fracture extension, and adversely affects the conductivity of the fracture. To overcome this problem, multiple stages of polymer pads are usually pumped in acid fracturing treatments to reduce leak-off. In addition, synthetic polymers are commonly added to the acid to produce gelled or in-situ gelled acids. The objective of adding these polymers is to reduce leak-off, by increasing the viscosity of the acid. This in turn reduces the rate of mass transfer of the acid to the rock surface. However, several studies have shown that these polymers can cause formation damage. Moreover, the cross-linker can precipitate in the formation causing further damage. Efficient mixing of synthetic polymers in the field is also a concern, especially when the polymers are present in a solid form.
To overcome problems associated with polymeric fluids, polymer-free fluids were used for the first time to acid fracture several vertical wells in a deep gas reservoir in Saudi Arabia. The acid fracture treatments consisted of several stages including: viscous pads, emulsified acid, in-situ acid and an inhibited acid. A visco-elastic surfactant system replaced the polymers used in the pad and the leak-off control acid (28 wt% HCl). Calcium chloride produced from acid reactions with the carbonate rock viscosifies the acid in-situ, reducing leak-off volume.
Simulation of Collapse Loads on Cemented Casing Using Finite Element Analysis
Authors: Rodriguez W. J. , Fleckenstein W. W. , Eustes A. W. 
Published: December 2007

Abstract
Collapse phenomenon behavior has been broadly studied in the petroleum industry but few changes have been implemented in this subject. Since the early 1960's when the American Petroleum Institute (API) published the Recommended Practice 5C3 for casing design equations under burst, collapse and tension, these equations have remained unchanged until the present.
These equations ignore the effects of the cement sheath on collapse resistance and assume uniform collapse loading of the casing. Incorporating the effects of a cemented wellbore improves collapse casing design. The study presented in this paper describes the effects on the collapse loading conditions of the mechanical properties of cement and rock formation surrounding the casing strings. In order to investigate these effects, the Finite Element Analysis technique was used. Three separate cases are studied: unsupported casing; casing with a cement sheath bonded outside of it; and casing, cement sheath, and consideration of the surrounded rock formation. For all of them, the same constant value of stress was applied at the outer boundary of each model. According to the results yielded by this study, improvements of up to 62% in casing collapse resistance can be achieved, depending on the mechanical properties of the cement systems and rock formation properties.
Imaging the Initiation of Asymmetrical Hydraulic Fractures in Laboratory Experiments
Authors: Zeng Zhengwen , Roegiers Jean-Claude , Grigg Reid 
Published: December 2007

Abstract
Asymmetrical hydraulic fractures have been observed in the field to reduce the efficiency of such stimulation treatments. Efforts have been made to investigate asymmetrical hydraulic fractures by imaging their initiation using microseismic imaging technology developed in-house. Images of the fracture initiation were generated using the located sources of microseismic events. Analyses of these images indicate that the initiation of an asymmetrical hydraulic fracture is a complex process. While asymmetrical fractures were generated under asymmetrical stress fields along the length direction, selective propagation along the height direction was also observed, as well as nonalignment and reorientation of the fractures near the borehole. Scarce distribution of microseismic events near the borehole may indicate poor connection between the far-field fracture and the borehole. Dense distribution of microseismic events near the borehole probably results from the coupled effect of fluid leakoff and stress-induced tensile fracturing.
The Study of a New Overall Hydraulic Fracturing Mode in Low Permeable and Unconventional Reservoirs
Authors: Jiang Tingxue , Wang Yongli , Ding Yunhong , Shan Wenwen , Wang Xin , Zhou Xiangguang , Liu Jixia 
Published: December 2007

Abstract
A new fracturing mode is put forward in the paper. Compared with the former mode, the new one has the following advancements: 1) Some key reservoir parameters such as effective permeability, effective thickness, loss coefficient, fracture azimuth and fracture height as well are all regarded as stochastic variables according to field statistic results; 2) Fracture length and conductivity are accordingly stochastic variables as a result of the random distribution of such fracturing treatment parameters as pumping rate, sand to liquid ratio, pad volume and sand volume as well; 3) As a result of undetermined reservoir and fracture variables, the post-fracturing rate is stochastic in most cases; 4) Monte Carlo method is utilized to perform economic analysis, and the relationship of net present value versus probability in a certain unconventional reservoir may be available on the base of above works, so that a decision-making policy may be determined accordingly. After that, one field case is hydraulically fractured utilizing above strategy, and the post-fracturing effect is very satisfied, which indicates that the new overall hydraulic fracturing mode put forward in the paper is reliable and if it is put in to field applications, a greater economic benefits may be expected.
An Update of Recent Production Responses Obtained from Devonian Shale and Berea Wells Stimulated with Nitrogen Foam (with Proppant) vs. Nitrogen-Only, Pike Co., KY
Authors: MacDonald R. J. , Frantz J. H. , Schlotterbeck S. T. , Adams B. , Sikorski D. 
Published: December 2007

Abstract
This study updates SPE paper 77464, which compared 97 nitrogen-foam (with proppant) stimulations versus 120 nitrogen-only completions performed in the 1990's in Pike County, Kentucky. Ninety-three of the 97 foam stimulations are located outside of a relatively high permeability area located in the northwestern portion of the study area. For analysis purposes, these 93 wells have been compared with 14 recent foam stimulations drilled throughout 2002 and the first quarter of 2003.
All wells are owned and operated by Equitable Production Company and are located in Pike County, Kentucky and are completed with two stages in the Devonian Shale and Berea formations. Our results indicate that the latest foam treatments outperform the earlier foam stimulations by a noteworthy percentage. This improved performance is most likely due to high-quality post frac clean-up methods, promptly turning the wells in line, and subsequent expert well maintenance.
There has been no significant change in stimulation design for the new wells when compared with the earlier completions, however the latest stimulations are utilizing a consistent design per well (e.g. ramping from 90Q to 75Q, standard proppant volumes sent downhole, similar pad size etc.), whereas the earlier stimulation designs tended to vary from well to well. In addition, line and annular pressures are similar, and reservoir qualities (e.g. relative permeability, net pay thickness, etc) are analogous between the earlier wells and new completions.
In furtherance of this study, the operator is continuing to pump foam with proppant in wells throughout the study area. The results of this paper are significant for Appalachian Basin operators utilizing nitrogen foam treatments since it quantifies the positive influence of rapid well clean-up and first-class well maintenance. Additional acreage is also being evaluated for use of this stimulation treatment, including evaluation of existing wells for restimulation potential. This is the first paper published to update results over such a large study area.
Fracture Height Development and Control in the Mississippian Sandstones of Central West Virginia
Authors: Mack David J. , Awny Joseph , Kendrick Daniel 
Published: December 2007

Abstract
Natural gas production in central West Virginia is primarily from the shales of Devonian age upward to the sandstones of Pennsylvanian age. These productive intervals are typically low permeability, under pressured and adjacent pay zones can have similar closure pressures with only a minimally competent barrier separating them.
Such a scenario exists in the Weir and Injun sandstones of Nicholas, Fayette and Kanawha Counties, West Virginia. At a depth of 2000 to 2500 ft, both the underlying Weir and overlying Injun exhibit only a few hundred psi reservoir pressure, frac gradients in the 0.4 to 0.6 psi/ft range and are separated by 10 to 20 ft of sandy shale. To make either of these zones commercially productive, both must be hydraulically fractured.
Initially it was felt that historical treatment data and the comparison of conventional electric logs to offset wells would provide sufficient data to effectively fracture model stimulation treatments. This technique provided interesting computer simulations, but treatment and production results did not substantiate the modeling.
In an effort to better model and stimulate both zones, mechanical properties were obtained from a sonic log. Treatment parameters such as pressure, fluid efficiency/formation permeability and near wellbore connectivity characteristics were obtained from step-down and mini-frac tests. Real-time job monitoring, post-frac RA tracer survey and production testing were performed to verify the design simulation.
Treatment design history and current philosophy will be discussed in this paper. In addition, the results of the data gathering, treatment design and execution and RA tracer survey will be presented.
Pulsed Water Injection During Waterflooding
Authors: Groenenboom Jeroen , Wong Sau-Wai , Meling Tor , Zschuppe Robert , Davidson Brett 
Published: December 2007

Abstract
During a half-year field test a novel method was applied for water injection during waterflooding in a weakly consolidated, heavy oil reservoir (90–120 cP). The injection has been combined with a hydraulic pulsing tool downhole in the injection well to provide additional dynamic pressure pulses on the order of 4–17 bar, with 5–6 pulses per minute. The technology has been developed in Canada and applied successfully, especially as a well stimulation technique in order to initiate or stimulate oil production with sand coproduction. The first objective was to see whether pulsing would be beneficial for the efficiency of the injection process. Furthermore, laboratory experiments and theoretical developments suggest that pulsing might improve the sweep efficiency of the flooding pattern. Hence, the promise of this technique would be potentially faster and higher oil recovery during waterflooding. In the design of the field test it was chosen to keep the total water injection rate on the same level as before pulsing was applied, on the order of 110 m3/d. The rationale behind this decision was that previous experience in the field has shown that higher injection rates resulted in pressurization of the reservoir and increased fingering. In addition, the fixed injection rate allowed us to focus on improvements in sweep efficiency, without correcting production figures for the higher injection rate.
Pressure Pulse Technology (PPT) was applied without any significant operational problems for half a year although severe corrosion problems unrelated to the PPT project were uncovered after the trial. Injection and production performance has been monitored before, during and after the test. When pulsing started, injection pressure dropped, and even after the pulsing stopped a lower wellhead pressure has been measured. With constant injection rate this shows an improvement in injectivity. It also indicates a significant reduction in near wellbore skin factor or possible improved injection conformance. The injection water used is considered dirty and potentially deteriorates injectivity over the life of the well. Indications are that injection pressure is now slowly building up again following the trial.
Improvements in production have not been confirmed by this field trial. The accuracy and repeatability of the production measurements have not assisted in identifying the potential effect. However, the field trial results have enabled us to recognize the potential use of the technology for an efficient high-rate injection strategy. Possibly this would avoid injection under fracturing conditions. We outline situations where such applications would be desirable. Higher injection rate and more efficient pulsed injection potentially lead to improved recovery, although actual improvements need to be assessed with further tests.
A Technically Rigorous and Fully Automated System for Performance Monitoring and Production Test Validation
Authors: Bruni Thomas , Lentini Amelia , Ventura Stefano , Gheller Ruggero , Maybee Charles A. , Pinedo Jorge E. 
Published: December 2007

Abstract
This paper describes the integration between a dynamic surveillance tool and a system analysis tool to provide the surveillance engineer with a new, fully automated and technically rigorous system, capable of true performance monitoring and reliable production test validation.
The combination of the software tools and workflows resulted in an innovative PROduction Management and Optimization system (PROMO), with new and extended capabilities beyond those of either of the stand-alone packages. Algorithms were defined in order to automatically compare actual and modeled production (taking into account FTHP variations) on a daily basis. Additionally, as new production test data becomes available, the system can automatically display it on a calibrated IPR plot for fast and rigorous validation. The system has also been designed such that when a new well test is approved and validated, the IPR curve will be automatically re-calibrated to honor the new performance measurements.
In principle no gas or oil field is outside the scope of such an application. Once an appropriate interface is set up to allow for data exchange between the surveillance and system analysis tools, it is a matter of building the appropriate processes that will yield the most beneficial results in terms of production optimization and data validation. The addition of data linkages to corporate data warehouses results in a system that requires little maintenance of input parameters and is always up-to-date with respect to the available data.
The PROMO system, currently deployed in one gas plant (comprising of seven offshore gas fields, 14 platforms and 180 production strings) and one oil plant (comprising of two onshore oil fields and 10 production strings), is allowing the production engineers to easily identify under-performing strings (completions) and promptly intervene. In addition to providing a more reliable and time effective production test validation process, the engineer can fully analyze current well performance with daily, historical and forecasted data. Additional benefits include calculation of historic SBHP’s from production tests, dependable production allocation (with great benefit for overall field management and reservoir modeling) and considerable time savings as pertinent data is automatically (as opposed to manually) handled and used in the system analysis algorithms.
Using Geological Knowledge Gained Through Special Seismic Studies To Provide A Strategy For Improved Oil Recovery
Authors: Cullen Andrew , Johnson Timothy. E. , Toulekima Serge , Miltos Xynogalas , Zhu Hua 
Published: December 2007

Abstract
There are many techniques beyond standard seismic interpretation that can help optimise and direct improved oil recovery. Firstly, an integrated approach involving a multi-scale analysis of petrography, image log analysis, seismic facies studies, petrophysics, AVO forward modeling and seismic inversion aid understanding the depositional system, burial history, diagenesis, deformation and fluid movement history of the reservoir. The resulting reservoir geometry and properties are used as direct input to a detailed static model, which is used to plan development activities in an optimum way. 4D forward modeling tied to dynamic modeling is used to test development scenarios and select optimum bore locations to help maximize production efficiency. A key element in ensuring the applicability of such work is the rock property constraints employed. A consistent methodology for deriving calibrated rock properties for such work is described. Examples of such an approach are given from several fields in Sabah where a variety of production challenges are encountered.
Propellant Perforation Breakdown Technique: Eastern Venezuela Field Applications
Authors: Boscan Jorge , Almanza Edgar , Folse Kent , Bortot Maximiliano 
Published: December 2007

Abstract
PDVSA operates the RG-231 and AM-102 wells, located in eastern Venezuela. The wells are characterized by stratified reservoirs and complex geology due to the presence of low permeability and porosity. The RG-231 well is in a gas reservoir with extremely low permeability (less than 0.02 md). During a well-testing operation, additional perforations were added to increase gas production. The AM-102 well was in an oil reservoir.
To effectively meet the operator’s needs for a method that would help to optimize well productivity and costs without compromising the results of the operation, a change from traditional perforating operations was required. A propellant-assisted perforating method to optimize well productivity while maintaining stringent health, safety and environmental standards was proposed. The propellant-assisted perforating method uses standard perforating components and procedures; thus, it was capable of providing the necessary safety features. The propellant is essentially an oxidizer that creates carbon dioxide gas at extremely high peak pressures in the millisecond time regime to overcome in-situ stresses and create perforation breakdown and mild fracturing near the wellbore.
This paper will focus on the method developed to satisfy the operational challenges specific to the PDVSA wells. The discussion will cover the results obtained by using propellant technology in a low-permeability, low-porosity reservoir as well as how the technique was capable of addressing the operator’s requirements in data acquisition as well as the difficult reservoir conditions. Instrumental in the success of the methodology was the combined use of super-deep penetration technology and propellant assisted perforation.
Waterflooding in Low N/G Fluvial Environment – Thai Shell Experience
Authors: Chuenbunchom Supamittra , de Bruijn Gerbert , Indran Devarajan , Akrapipatkul Piti 
Published: December 2007

Abstract
Thai Shell operates three onshore oil fields producing from the Yom/Pradu Tao Formations in the Phitsanulok Basin in Thailand: Sirikit D block, Thap Raet and Sirikit West. The Yom/Pradu Tao Formations originate from a low energy fluvial depositional environment with a low net-to-gross ratio of 20–40%. After a comprehensive evaluation of EOR methods, waterflooding was found to be the most attractive development concept to achieve a significant increase in recovery factor in the Yom/Pradu Tao reservoirs. However, waterflooding in a complex low net-to-gross fluvial environment is not straightforward. Thai Shell has followed a step-by-step approach in the implementation of waterflood starting with the Sirikit-D block in 2000, which is geologically least complex, followed by Thap Raet in 2001. Sirikit D block and Thap Raet are both showing a positive response to waterflooding, substantially increasing production and reserves. Sirikit West, the largest and geologically most complex of the three fields, has started water injection in May 2003. Prior to the implementation of waterflood in Sirikit West, the field had been subjected to extensive studies using multiple static and dynamic model realizations. This paper will provide an overview of the experiences and performance of waterflooding to date in the Sirikit-D and Thap Raet fields. In addition, it will explain the modeling approach and waterflooding plans in the Sirikit West field.