bluuebunny/crossref_metadata_2025_split huggingface dataset:
Formation Testing While Drilling, a New Era in Formation Testing
Authors: Proett Mark , Walker Mike , Welshans David , Gray Charlie 
Published: December 2007

Abstract
This paper introduces a new technology in which a logging while drilling (LWD) tool is used to pressure test a formation during the drilling process. The Formation Testing While Drilling (FTWD) or GeoTAP* tool described in this paper uses a testing technique similar to wireline formation testers. A probe is extended to the formation and a small sample chamber is used to pressure test the formation. The drilling environment offers many new challenges to pressure testing, however.
Wireline tools require a great deal of interaction with the engineer, which is very limited in the drilling environment. Therefore, the new tool has up-link and down-link capabilities and is highly automated for test control. New data compression routines are described that enable not only some of the raw data to be transmitted, but formation permeability (mobility) and test quality estimates to be obtained in realtime. An efficient algorithm is used down-hole to analyze the data where testing parameters and selected pressure data are transmitted to the surface in real-time for continuous monitoring of the test.
The drilling environment is more dynamic than is the case for wireline testers. This environment is modeled using a finite element simulator to show the effects these dynamics might have on pressure measurements. The results show that even in this highly dynamic state it is possible to obtain reliable pressure measurements.
Field data from the new GeoTAP tool is presented and compared with wireline formation test (WFT) data in test wells. The new tool requires the drill pipe to stop rotating/sliding for about 7 minutes per pressure test. During this time the pumps can be turned on or off. Most of the test very favorably with WFT data in terms of the absolute pressure measurement, repeatability and accuracy. The field example demonstrates the robustness of the measurement with three repeat pressure tests that were taken at three different depth points where, in each case, the pressures recorded were within 1 psi. Final conclusions are drawn regarding FTWD technology and its future direction.
Formation Pressure Testing During Drilling: Challenges and Benefits
Authors: Meister M. , Lee J. , Krueger V. , Georgi D. , Chemali R. 
Published: December 2007

Abstract
Formation pressure testers are utilized to measure formation pressure along a wellbore. From the data reservoir engineers develop information on formation fluid type, fluid contact depths, and formation connectivity. Together with recovered fluid samples, these data provide crucial exploration and development information for oil and gas fields. Until recently, pressure measurements were performed with wireline tools or during production and drill stem testing. Notably, these methods can only be used after the borehole is drilled and the drill string is pulled out of the hole.
A formation test-while-drilling tool has been introduced to provide formation pressures during a brief pause in the drilling. The tool is equipped with an intelligent control system to perform closed loop, controlled drawdown-buildup tests in less than 5 minutes. Individual tests are controlled and analyzed with the FRA (Formation Rate Analysis) method in real time while repeat tests are optimized based on the previous test data. The formation pressure data can be utilized directly to choose the casing points and adjust the mud weight and ECD (Effective Circulation Density), thus allowing one to increase the drilling efficiency and safely drill into high pressured zones. As with wireline tools, the data also can be used to establish fluid gradients and fluid contacts and to analyze the connectivity between reservoirs.
Analyzing Reservoir Fluid Composition In-Situ in Real Time: Case Study in a Carbonate Reservoir
Authors: Go Fujisawa , Mullins Oliver C. , Dong Chengli , Carnegie Andrew , Betancourt Soraya S. , Terabayashi Toru , Yoshida Satoko , Jaramillo Antonio R. , Haggag Mostafa 
Published: December 2007

Abstract
Near-infrared (NIR) spectroscopy is used to provide in-situ quantitative characterization of reservoir fluids during wireline sampling using five representative composition groupings (C1, C2–C5, C6+, CO2, and water). This information is vital for the proper execution of wireline fluid sampling jobs. Time variances of fluid compositions, along with absolute compositions, give us important clues about the phase and contamination level of the capturing samples in real time. In addition, quantitative compositional analysis during wireline sampling provides immediate identification of the critical fluid issues, thereby enabling optimization of the sample acquisition program. Laboratory pressure-volume-temperature (PVT) analysis requires samples that are captured in single phase and are relatively free from mud filtrate contamination. Such information is essential for reservoir management and flow simulation modeling.
This paper consists of three parts. The first part covers laboratory NIR spectroscopic study of petroleum fluids at elevated pressures and temperatures. This extensive database, coupled with principal components regression (PCR) technique, establishes the feasibility of such an in-situ compositional analysis.
The second part reports shop test results on a downhole experimental prototype. The tool estimates density for each composition group for more than 10 live fluids at conditions simulating a petroleum reservoir. Typically, the measured mass fraction for each composition group agrees with the mass fraction acquired from PVT analysis within ±5% accuracy.
The final part presents a field test case study conducted in an onshore carbonate reservoir in the United Arab Emirates (UAE). A gas injection pilot has been running for years, and a comprehensive monitoring program is in place. The first field trial of the subject technology in an observation well successfully identified the presence of injected gas, as determined by fluid compositions. This result was later found to be in good agreement with laboratory PVT analysis.
High Power/High Frequency Acoustic Stimulation – A Novel and Effective Wellbore Stimulation Technology
Authors: Wong Sau-Wai , van der Bas Fred , Zuiderwijk Pedro , Birchak Bob , Han Wei , Yoo Kwang , van Batenburg Diederik 
Published: December 2007

AbstractReduced production is often caused by local impairment of the formation permeability due to the interaction of the reservoir with drilling and completion fluids. The problem may be further compounded by impairment caused by fines migration during production.High frequency sonic and ultrasonic waves have been used in many industrial applications to remove contaminants like dirt, oil, and grease from parts immersed in fluids. An obvious extension of this application is the removal of wellbore impairment by exposing it to high frequency acoustic waves. The influence of high frequency waves is limited to the near wellbore environment due to high attenuation. Dedicated experiments under realistic downhole conditions have been carried out in both linear as well as radial configurations. We have examined the acoustic power needed to remove near wellbore formation damage due to fines and particles plugging and drilling induced damage. Specific issues related to well completion and envelope of acoustic stimulation are presented. The laboratory results have led to the design and construction of a slim, high power and high frequency (above 10 kHz) downhole acoustic tool for field deployment.This paper outlines the concept and presents key experimental results to support the claim. Key features of a prototype downhole tool are described.
Improvement Processes for Coalbed Natural Gas Completion and Stimulation
Authors: Olsen T. N. , Brenize Galen , Frenzel Taryn 
Published: December 2007

Abstract
Drilling activity to access natural gas production from coalbeds has increased dramatically in the past decade; however, the percentage of methane that has been converted to economically recoverable reserves remains only a fraction of the potential gas in place. One of the methods widely used to access natural gas from deeper, lower-permeability coal seams, has been with propped hydraulic fracture completions in vertical wellbores. Propped hydraulic fracture completions have been successful in stimulating production from conventional reservoirs from microdarcy to darcy rocks. Effective fracture lengths in excess of 1,000 ft have been documented from pressure transient analysis with skin effects as low as −6.5. Propped hydraulic fracture completions in coalbed natural gas wells have been successful in stimulating production, but have generally under performed the stimulation effects that are observed in conventional sandstone reservoirs. In spite of the fact that coal seam fracture stimulation volumes can be 3,000 to 12,000 lbm/ft of coal, effective fracture lengths are rarely documented beyond 200 ft, and post-fracture skins have been measured near zero or even positive in some cases. It can easily be estimated that if fracturing in coal seams could be brought up to parity with sandstone fracture stimulation, the recoverable reserves from coal seams could be tripled over today's standards.
This paper investigates three processes in coalbed fracturing that can inhibit stimulation effects and offers solutions that can increase coal stimulation efficiency. The effects of maximum horizontal stress azimuth in relation to cleat orientationPropped fracture placement efficiencyThe effects of fracturing fluid damage in coal cleats
Environmentally Favorable Terpene Solvents Find Diverse Applications in Stimulation, Sand Control and Cementing Operations
Authors: Curtis James 
Published: December 2007

AbstractEnvironmental regulations on the usage of toxic aromatic solvents such as xylene and toluene are becoming increasingly restrictive. Yet, whenever organic deposits are encountered, an effective solvent is still needed to achieve a successful completion or workover. Clearly, an environmentally favorable replacement for aromatic solvents is required.Terpenes are a renewable resource derived from plant products such as orange peels and resinous pine sap. They have been used for years in many industries in diverse applications. Compared to aromatic solvents, terpenes have good solvency and are biodegradable, less toxic and less flammable.This paper reviews how terpene solvent mixtures have been used over the last several years in a multitude of oilfield applications, including wellbore cleanouts, matrix stimulation, hydraulic fracture stimulation, sand control, and cementing operations. It is described how in several operating areas, aromatic solvent usage has been completely eliminated in favor of terpene solvent blends.
Novel Carbonate Well Production Enhancement Application for Encapsulated Acid Technology: First-Use Case History
Authors: Blauch M. E. , Cheng A. , Rispler K. , Khallad Abe 
Published: December 2007

Abstract
Production from carbonate wells is often controlled by the degree of stratigraphic interconnectivity or lack thereof. Formation stratigraphy results in severely compartmentalized reservoirs. Effective methods for achieving hydraulic interconnectivity with such compartments are limited in horizontal openhole and long pay section in deviated wells. A new technology is emerging that incorporates solid acid capsules that function as both a fluid-diverting agent and a fracture conductivity enhancer. The degradable sized particulate system is incorporated into the acidizing fluid designed to enhance inflow from natural fracture swarms and to help enable propagation of hydraulic fractures that can breach or achieve wellbore communication with the stratigraphic compartments.
This paper presents a case experimental project that involves a Canadian carbonate gas reservoir. Historically, horizontal wells drilled in low-permeability reservoirs with no natural fractures have shown poor production response. This successful production stimulation case demonstrates the potential to overcome the compartmentalization problem. In one of the first-use case wells reviewed in this paper, up to a 10-fold increase in reservoir pressure was observed in a shortterm buildup test, and the well was converted into an economic producer. Image logs were used to provide location and distribution of mineralized natural fracture swarms targeted for stimulation. Production data, laboratory data and post-treatment productivity index (PI) are presented.
This paper adds to the industry's technical knowledge base by: (1) offering a practical, lower cost, high value solution to a significant emerging market; (2) documenting the first use of a new technology application; (3) presenting evidence of the technology's widespread global application to carbonate reservoirs and possibly sandstone reservoirs.
Development and Validation of a Sandstone Acidizing Model with a New Permeability Response Model
Authors: Rodoplu S. , Zhu D. , Hill A. D. , Zhou H. 
Published: December 2007

Abstract
A large effort has been devoted over the years to modeling of the sandstone acidizing process. Yet, there has been little laboratory validation of the models that are being used. In fact, most comparisons between theoretical models and experiments are still made with just one set of laboratory results - those of Lindsay1 conducted with 3 inch Berea cores over twenty-five years ago. In this paper, we implement a rigorous model of the permeability response to a sandstone acidizing simulator. The permeability model includes the effects of changing rock morphology and mineral distribution on permeability prediction. We conduct a series of sandstone acidizing core flood tests, and verify the model by comparing it with new laboratory data. This comparison not only provides a validation of the permeability model, but also of the two-acid, three-mineral model of sandstone acidizing2, a commonly used model of the sandstone acidizing process. The applicability of the sandstone acidizing model to field applications is then illustrated by history-matching the actual response during a well treatment with the model.
Laboratory Study of Gas Trapping in Foam-Acid Diversion
Authors: Xu Q. , Rossen W. R. 
Published: December 2007

Abstract
A series of Berea coreflood experiments modeled the process of foam-acid diversion for well stimulation. Foam was injected to steady state, followed by injection of liquid to represent acid. Pressure gradient was monitored along the core and average liquid saturation was determined by weighing the core continuously during the experiments. This approach provides direct data on liquid saturation and liquid relative permeability during foam injection and liquid injection after foam.
Water saturation increased by a larger amount during postfoam liquid injection than estimated in previous studies. The liquid relative-permeability function krw(Sw) obtained during foam injection was reasonably accurate during post-foam liquid injection, until gas dissolution into the injected liquid became significant. The ultimate trapped-gas saturation during liquid injection appears to depend on previously injected foam quality; this may require a revision of models for the acid-diversion process.
It appears that a sufficiently high foam quality (injected gas fraction) can eliminate the detrimental decline in pressure gradient observed during liquid injection in earlier studies. This may alter previous ideas about the optimal foam quality for foam-acid diversion.
Modeling And Implementation Of A System For Sucker Rod Downhole Dynamometer Card Pattern Recognition
Authors: Schnitman L. , Albuquerque G. S. , Corrêa J. F. , Lepikson H. , Bitencourt A. C. P. 
Published: December 2007

Abstract
This paper presents a new method for the downhole dynamometer card pattern creation. This method use artificial intelligence concepts and real card data picked up from the oil fields acquired data. The main idea is to allow field team to generate patterns based on their own experience supported by an intelligent algorithm designed to perform graphical analysis of the card shape.
The main idea is to allow pattern recognition and its classification toward the solution of rod pumping problems in oil wells. Successful results were reached when the proposed method was applied in PETROBRAS/UN-BA real databases. Tests performed with real data allowed the development of a new set of patterns used to analyze well performance in Buracica and Balsamo oil fields. These tests showed good results when compared with the ones obtained from empirical patterns only. In addition, this approach allowed to immediately increasing the pattern number from two to a set of eight, improving the sucker-rod pumped wells analysis and management.
Reserves Growth: Enigma, Expectation or Fact?
Authors: Beliveau Dennis , Baker Richard 
Published: December 2007

Abstract
The phenomenon of "reserve growth" in established fields has been discussed by several authors, and described as a surprise or even an "enigma". This study uses the Alberta Energy and Utilities Board (EUB) historical reserve database to show the evolution of proved reserves versus time for oil pools in the Western Canadian Sedimentary Basin (WCSB), and demonstrates the consistent, long-term growth in reserves associated with the majority of these pools. The advantage of looking back at the performance of these fields is that many of them are very mature, so actual cumulative recovery levels are now very close to the estimates of expected ultimate recovery. We discuss the regulatory, business and technical reasons for these reserve changes and growth trends. Thoughts about the future growth potential of these reservoirs are also presented.
Irreducible Uncertainty — A Fact of Life in Reserve Estimates
Authors: Wright John D. 
Published: December 2007

Abstract
It is commonly assumed that more production data will lead to "bettef' estimates of remaining reserves. This is not necessarily correct. This paper reviews several real-world examples that disprove this hypothesis. Examination of reserve estimates on the same fields over several years demonstrates there is always a significant amount of irreducible uncertainty associated with reserve forecasts - even for proved developed producing properties. Furthermore, the percentage error in remaining reserves is still significant after many years of production.
Applied Reservoir Management Principles with Case Histories
Authors: Ezekwe John N. 
Published: December 2007

Abstract
Applications of technically sound reservoir management strategies to new and old reservoirs are important for maximum economic recoveries. Correct identifications of key geologic features, rock properties, state of reservoir fluids and major recovery mechanisms determine applicable reservoir management strategies. The critical decisions are selections of strategies that consider all available data and incorporate current technologies. The management strategies applied must be economic, conserve reservoir energy and adaptable to emerging technologies. Five reservoir management principles are presented as guides for determination and implementation of reservoir management strategies. The reservoir management principles are:
Conservation of reservoir energy Early implementation of simple strategiesSustained and systematic collection of dataContinuous application of improved recovery technologiesLong term retention of staff in multi-disciplinary teams
Case histories of 26R Reservoir, MBB/W31S Reservoirs, Luling and Slick Reservoirs are reviewed to illustrate the applications of the five reservoir management principles. The main objective of the report is to demonstrate through case histories that applications of the five reservoir management principles lead to technically sound reservoir management strategies that lead to maximum economic recoveries.
Developing Sub-Sea Cuttings Re-Injection Technology for Application in the Caspian Sea
Authors: Maggiori David , Reith Charlie 
Published: December 2007

Abstract
Over the past 5 years there has been a dramatic increase in the profile of BP's business activities in Azerbaijan. The Chirag Early Oil Project is delivering around 130,000 bbls / day and is in the middle of an extended reach drilling program.
Phase 1 of the ACG (Azeri, Chirag, Guneshli) Full Field Development (FFD) was sanctioned in 3Q 2001 giving the green light to detailed engineering for a 48 well platform with 9 pre-drill wells planned to commence through a template in March 2002. These wells will be suspended and tied back to a platform in 2004 for early oil production.
The Dada Gorgud Semi-submersible was contracted to drill these wells with zero discharge. BP and its partners decided to develop a dedicated Sub-sea Cuttings Re-injection System to dispose of drilled waste during this campaign.
This paper describes the process of Sub-sea CRI system development, focusing in on key areas of technology development such as corrosion/erosion resistance, horizontal tree design, new sub-sea interface technology and the surface cuttings processing system. General discussions around Project Management, Sub-surface and well design, will attempt to describe to the reader some of the challenges faced throughout this project.
CO2 Sequestration Potential of Texas Low-Rank Coals
Authors: Garduño Jorge Luis , Morand Henri , Saugier Luke , Ayers W.B , McVay Duane A. 
Published: December 2007

Abstract
Fossil fuel consumption is a primary source of CO2, a major greenhouse gas. Geologic methods, such as injection and sequestration of CO2 in coals may offer viable methods of reducing CO2 atmospheric emissions, while providing the added benefit of enhanced coalbed methane recovery.
The potential for CO2 sequestration in low-rank coals is unknown, and it differs significantly from bituminous coals. To evaluate the feasibility and the environmental, technical, and economic impacts of CO2 sequestration in Texas low-rank coal beds, we are conducting a 2-year study to characterize the coals located near major electrical power plants. We have identified potential of CO2 sequestration sites in coals near 3 Texas power plants. These 3 power plants discharge 34,068,751 short tons of CO2 annually, accounting for 14.6 % of Texas' point-source emissions.
On the basis of preliminary modeling of one site, using assumed permeability, CO2 storage and methane content values, we conclude that 360 wells on 80-acre spacing could sequester CO2 emissions for the Gibbons Creek plant for 11 years, while producing 90 Bcf of coalbed methane. However, reservoir properties are poorly known and, thus, the volumes of CO2 that may be sequestered and the amount of methane that may be produced are speculative at present. Future study will focus on better reservoir characterization and additional modeling.