bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Development
Authors: Colwart George , Burton Robert C. , Eaton Luke F. , Hodge Richard M. , Blake Kenyon 
Published: December 2007

Abstract
ConocoPhillips is developing the Magnolia field with a tension leg platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells produce primarily from thick, fine-grained, Pleistocene-age reservoirs. Due to the long lengths of the producing reservoirs and large variations in sand grain sizes/permeabilities, premium screens with shunt tubes in conjunction with cased hole frac packs have been used to complete the wells.
The third well, A1ST1BP1, was completed using the same techniques as were successfully used on the first two wells. The A1ST1BP1 completion failed during initial unloading, allowing unacceptable rates of sand production. The well was worked over and the tubing with eight control lines and premium sand control screen with shunt tubes were retrieved/fished from the well with minimal problems. The retrieved screens had collapsed around the perforated base pipe. The well was re-perforated, new screens run and a second frac-pack pumped. When laying down the washpipe after the second frac-pack, erosion marks indicated an apparent second screen failure.
A detailed examination of both A1ST1BP1 frac-pack jobs was conducted in conjunction with laboratory collapse and erosion testing of the premium screens. Collapse testing revealed the screen lost sand control at less than 1000 psi. The collapse rating stated by the manufacturer was greater than 7000 psi. The erosion tests demonstrated that inflow from supercharged reservoirs into the wellbore could erode hole(s) in the premium screen. Revised operational procedures were used in six subsequent frac-packs without any additional failures and zero to negative completion skins.
This paper will discuss the failure modes of the two frac-pack/premium screen sand failures, workover planning and execution to remove tubing with multiple control lines and fish screens with shunt tubes from close tolerance casing, as well as procedural revisions developed to successfully frac-pack the subsequent Magnolia reservoirs.
Application of a Hybrid Dual Porosity/Dual-Permeability Representation of Large-Scale Fractures to the Simulation of a Giant Carbonate Reservoir
Authors: Uba Halilu M. , Chiffoleau Yann , Pham Tony , Divry Vincent , Kaabi Abdulaziz , Thuwaini Jamil 
Published: December 2007

Abstract
The simulation of fluid flow in fractured reservoirs is mostly based on the Warren-Root formulation in which the matrix is dissected into blocks by fractures(1). In modern simulators, the Warren-Root formulation has been extended to account for fluid flow in the matrix as well as in the fractures(2). These two media of contrasting transmissibility and storage capacity constitute the basis of dual porosity dual permeability modeling. Hydraulic connection between the two media is managed via a transfer function. This formulation is appropriate for cases with diffuse interconnected fractures. Alternatively, fractures can be modeled explicitly by capturing their geometries, shapes and sizes in the form of numerical grid cells. But this would be prohibitively costly in terms of run time and memory.
This paper presents a method that is suitable for giant fields that are dominated by clusters of sub-vertical fractures called fracture corridors. It is based on a hybrid approach of the two alternatives mentioned. The effective Warren-Root and fracture parameters are adjusted to mimic explicit fracture modeling thereby capturing the advantages of both. The method was applied to a giant carbonate field in Saudi Arabia, which has both fracture corridors and super-permeable bodies. These bodies are typically horizontal and they inter-connect with the fracture corridors to form a combined high conductivity medium which is responsible for the unusual water movement observed in some parts of the field. The full field simulation model contains a homogeneous matrix and a fracture grid comprised of fracture corridors and super-permeable bodies. Fluid segregation is assumed in the fracture system in agreement with the physics inside conductive vertical fractures. The matrix-fracture corridor and the matrix-super permeable body exchanges are represented in a manner similar to matrix-fracture transfers in the Warren-Root dual-porosity system. Special attention was paid to matrix block size and to imbibition capillary pressure. This approach led to a reliable history match that captures the water arrival time and water production profiles in the reservoir.
Detailed Post-Event Analysis of Drilling Problems Significantly Alters the Root Cause Reality for Technical Sidetracks
Authors: Blaasmo Marit , Singelstad Arne V. , Bekkeheien Kjetil 
Published: December 2007

Abstract
Statoil has drilled an average of 30 technical sidetracks yearly since 2000, and a significant portion of the total drilling and well technology costs is related to these operations. A two-year project was initiated in 2004 to investigate the causes for the technical sidetracks. The project's main objective is to reduce drilling cost related to technical sidetracks.
One of the main activities in the project is the detailed post-event analyses to capture the root causes of the technical sidetracks. The analysis process includes, amongst other factors, interpretation of time based drilling and formation evaluation (FE) data. This activity was conducted throughout 2005 and is still ongoing. A total of 24 detailed analyses have been concluded with a direct cause and a corresponding root cause. The three major findings from these analyses were: Little consistency between reasons for sidetrack reported in daily drilling reports compared with root causes found from the detailed analyses.Marked reduction in formation related causes.Operational practice accounts for 10 of the 24 technical sidetrack root causes.
The majority of the technical sidetracks, according to the daily drilling report system, is due to formation related problems. However, the findings from the detailed analyses conclude that operational practice constitutes the major root cause. The picture is somewhat more differentiated, since the complex nature of some incidents results in several root causes related to both downhole mechanisms and operational practice.
These observations enforce an increased focus on the operational practice, i.e. how to conduct specific drilling operations and also how to handle drilling challenges. This paper presents why this knowledge is of great value during both planning and operations phase. Furthermore, it concludes that this type of detailed analysis significantly accelerates the learning outcome with regards to drilling operation challenges and the diagnosis of these, thus promoting a more proactive working methodology throughout the organization.
Improved Method for Use of Chelation to Free Stuck Pipe and Enhance Treatment of Lost Returns
Authors: Montgomery John K. , Keller Stuart R. , Krahel Nancy , Smith Martin V. 
Published: December 2007

Abstract
This paper describes how intentionally increasing the permeability of a non-aqueous fluid (NAF) filter cake can enhance treatments to free differentially stuck pipe and recover from lost returns. NAFs are well known for their ability to deposit thin, low-permeability filter cakes that reduce the risk of differential sticking. Yet, differential sticking still occurs and techniques to free the pipe have largely been ineffective. In addition, lost returns in NAF continue to be one of the industry's most difficult and expensive problems to solve.
The operator has developed an improved technique to increase the permeability of a NAF filter cake. The technique involves locally soaking the cake using a combination treatment that first conditions the cake and then removes a significant amount of the weighting material. Laboratory experiments have shown the technique can increase cake permeability by more than 850 fold.
There are at least two applications for this treatment. In the first, a pill is spotted across pipe segments (e.g., drill collars) believed to be differentially stuck. By increasing the cake permeability, pressure is allowed to penetrate the cake underneath the pipe, allowing it to more easily become free. Dissolving barite also reduces the shear strength of the filter cake, which may also facilitate freeing stuck pipe.
A second application is to enhance the performance of high fluid loss lost circulation material (LCM) treatments after NAF has damaged the fracture face permeability. Increased permeability enhances loss of the LCM carrier fluid and development of the immobile mass required to stop the growth of the fracture induced during lost returns. Formation integrity can then be rebuilt using rock mechanics-based techniques.
Feasibility Study of In-situ Combustion in a Carbonate Reservoirs
Authors: Mostafavi S. Vahidreza , Kharrat R. , Razzaghi S. 
Published: December 2007

Abstract
Heavy oil recovery studies is now being carried out in Iran since there is remarkable amount of heavy oil bearing formations in this country.
KMO oil field is one of the most important oil fields in which the different recovery methods are being investigated. However, due to very high viscosity the in-situ combustion process seems to be feasible. This field contains heavy oil with very low API degree, near eight, in Sarvak and Asmari formations.
To investigate the feasibility of this process, in-situ combustion tube tests on KMO rock and oil have been carried out. Through these experiments combustion front temperature was about 500° C. Additionally combustion front velocity and recovery has been measured. The amounts of oxygen, carbon monoxide and carbon dioxide have been measured by analyzing the effluent gas.
One of the risks of running combustion process in carbonate formations is the probability of decomposition due to very high temperature. While decomposition occurs in dolomite or lime stone, the rock will change in to a powder like material that will definitely cause plugging. The carried out tests along with TGA/DSC tests done show that there is no risk of decomposition in KMO reservoir rock around the temperature attained in the combustion front.
Finally, the results of the experiments were simulated to predict and investigate the effect of fractures contribution to the process.
Effects of RPM and ROP on PDC Bit Steerability
Authors: Ernst Stephen , Pastusek Paul , Lutes Paul 
Published: December 2007

Abstract
Directional drilling is a critical necessity in many of today's wells. Accurate prediction and awareness of achievable build rates is vital in lowering drilling cost. The science behind controlled wellbore deviation has advanced beyond prediction based solely on BHA geometry. Although BHA configuration is an important factor, interaction between each of the four primary components (bit, BHA, operating parameters and formation) must be evaluated thoroughly.
Previous papers have described how changes in bit characteristics, BHA configuration and various formations influence build rates. With regards to operating parameters, weight-on-bit (WOB) is well-known to be beneficial in increasing the desired build rate under certain drilling conditions and yet does not help in other situations.
We propose that most of the weight-on-bit effects are actually due to its influence on rate of penetration and bit tilt. However, the influence of operating parameters has not been fully investigated. RPM has been neglected as a significant influence on steerability. In theoretical studies, these properties have been measured and quantified with the use of a full scale drilling laboratory and commercially available PDC bits. This paper investigates the effects of RPM and ROP on build rate and illustrates the importance of these parameters. Practical guidelines for understanding the effect of operating parameters on steerable systems are also provided.
Demonstrating Managed-Pressure Drilling With the ECD Reduction Tool
Authors: Bansal R. K. , Brunnert D. , Todd R. , Bern P. A. , Baker R. V. , Richard C. 
Published: December 2007

Abstract
The equivalent circulation density reduction tool (ECDRT) is designed to counter the increased fluid pressure in the annulus caused by friction loss and cuttings load by reducing the total hydrostatic head. The tool has a broad range of drilling applications, including: narrow pore/fracture pressure margins in deep water and their effects on casing setting-depth selection; wellbore instability; depleted reservoirs; and extended-reach wells.
This paper describes progress on development and testing of a prototype ECDRT. The prototype was recently tested in a BP onshore U.S. Arkoma asset operation in southeastern Oklahoma. The primary objectives of the field trial were: 1) determine ECD reduction performance; 2) establish reliability in field conditions; and 3) evaluate the ECDRT operational procedures. The test involved drilling 8.75-in. hole with the tool running inside 9.625-in. casing cemented at a depth of 4,500 ft. Performance was monitored continuously from a real-time display of surface and downhole measurements.
Wellbore pressure management was clearly demonstrated in the field trial. The ECDRT consistently reduced ECD by about 150 psi, or the equivalent of about 0.7 ppg at 4,500 ft. Drilling performance was not limited in any way by the ECDRT. Fluid returns and wellbore cleaning were normal throughout the drilling operation. The ECDRT processed cuttings generated by the drilling at 100 ft/hr without difficulty. More than 500 ft of hole was successfully drilled before the tool was pulled because of difficulties with the directional drilling system. The final goal to evaluate ECDRT operational procedures was achieved as performance indicators on the surface worked reliably to diagnose the operational status of the tool.
Post-well analysis showed that there were still some design issues to secure the longevity and sustained performance of the tool. The tool demonstrated the ability to manage annular pressure under actual drilling conditions.
Nuclear Magnetic Resonance Logging: While Drilling, Wireline, and Fluid Sampling
Authors: Seifert Douglas J. , Akkurt Ridvan , Al-Dossary Saleh , Shokeir Ramez , Ersoz Haluk 
Published: December 2007

Abstract
Over the past decade, results from Nuclear Magnetic Resonance (NMR), logs have added significant value to petrophysical analysis by providing total, free-fluid and bound-fluid porosities. The development of Nuclear Magnetic Resonance tools for the LWD environment allows this valuable information to become available during the drilling operation, before significant invasion, allowing timely decisions, as well as reduced borehole risk.
Data from a Nuclear Magnetic Resonance Logging While Drilling tool (MRIL-WD) was acquired in a recently drilled well in Saudi Arabia. This well was extensively cored and logged. In addition to LWD NMR, wireline NMR logs (MRIL-Prime), and NMR fluid analyzers (MRILab) were also run.
This paper, following a brief discussion on the operation of MRIL-WD tool, compares and contrasts the results between while-drilling and wireline NMR logs. NMR fluid properties obtained from the NMR Fluid Analyzer are also crosschecked with the log data.
Obtaining Nuclear Magnetic Resonance data earlier in the drilling process will allow NMR logging to become one of the backbones of formation evaluation.
A Systematic Approach to Remove Iron Sulphide Scale: A Case History
Authors: Leal Jairo , Solares J. Ricardo , Nasr-El-Din H. A. , Franco Carlos , Garzon Francisco , Marri Hamad M. , Aqeel S. A. , Izquierdo Guillermo 
Published: December 2007

Abstract
A number of Khuff reservoir gas condensate wells have been on production for more than twenty years in Saudi Arabia. Many of these wells are classified as sour gas producers with hydrogen sulfide levels upwards of 10 mol% and carbon dioxide of 4-5 mol%. Most wells are completed with C-95 tubulars to withstand high stimulation treatment pressures. Condensed or formation water production rates range from 2 to 100 BWPD. The condensate to gas yield ranges from 30 to 250 BBLS/MMSCFD depending on the area of the field. Recent extensive lab work indicated that the iron sulfide scale deposits observed in the production tubulars of a number of wells comprised various types of iron sulfide, iron carbonate and calcium carbonate compounds.
Removing iron sulphide scale is a complex process, especially at downhole temperature and pressure conditions (285°F and up to 7,000 psi. in Khuff gas producers). Inorganic acids cannot dissolve all types of iron sulphide scale. As iron sulphide scale (FeS) ages, it is converted into pyrite (FeS2) which is insoluble in mineral acids. Moreover, iron sulphide is oil-wet, a condition which creates a protective organic coating that minimizes contact with acids and chelating agents. Furthermore, the hydrogen sulphide released during the acid dissolution of acid-soluble scale may cause serious problems, because the spent acid may redeposit iron sulphide and elemental sulphur.
This paper describes a systematic approach pursued to identify the optimum methodology to effectively remove complex iron sulphide scale in Khuff reservoir gas producers ahead of field trials. A discussion on iron sulphide scale dissolvers and an optimized mechanical scale removal using fluidic oscillation technology is included. Details of a significant number of dissolution tests conducted are shared.
Encountering an Unexpected Tar Formation in a Deepwater Gulf of Mexico Exploration Well
Authors: Weatherl M. H. 
Published: December 2007

Abstract
Industry experience reveals that tar formations can present significant challenges in deep water drilling operations (1-4). In a case where several feet of active tar is present at depth, substantial trouble time often results. Tar can even prevent reaching programmed depth in some cases. These difficulties are further compounded in a high cost environment with limited rig availability where project appraisal and viability can be impacted (5).
These events came to pass for Chevron and partners during late 2005 and early 2006 on the ‘Big Foot’ Prospect in the Gulf of Mexico at Walker Ridge Block 29 (see Fig. 1 Walker Ridge Area). Challenges on this sub salt prospect included loop currents, an active hurricane season, and numerous subsurface issues related to geologic uncertainty, narrow pore pressure/fracture gradient margins, and wellbore stability.
This paper will focus primarily on issues related to the tar formation which was encountered below salt, its impact on operational strategy, lessons learned, and steps taken to ultimately achieve the well objectives.
Premature Yielding Identified in First Comprehensive 2-million-lbm Deepwater Landing String Test Program
Authors: Bradford Dale W. , Payne Michael L. , Schultz Donald E. , Adams Burt A. , Vandervort Kurt D. 
Published: December 2007

Abstract
The purpose of this paper is to present the results of a comprehensive test program conducted with five different sets of deep-water landing string handling equipment consisting of both conventional and unconventional technology. A thorough presentation will be made detailing initial testing at elastic loads approaching yield and final high load testing beyond yield. All stages of the test program will be discussed including original testing protocol, test setup, testing performed, test results, and overall conclusions. This is one of the first standardized test programs used across five different designs of handling equipment. This overall presentation of the test program is made to identify stress levels associated with the extreme loads that occur when landing very heavy casing strings in deep-water wells.
Application of Purpose-Built Rig Technology Results in Step Change of Drilling Time, Cost, and Opportunities
Authors: Kolstad E. S. , Steinke L. D. , Brady L. S. , Marchand S. P. 
Published: December 2007

Abstract
The Piceance Basin, located in Western Colorado, is a 6,000-square-mile basin consisting of vertically stacked sand-shale sequences. Gas-in-place estimates exceed 200 trillion cubic feet. The operator started developing its acreage in 1982 with 160-acre bottom-hole spacing. Over time, dictated by reservoir performance and enabled by drilling and completion technology, such as PDC bits and directional drilling, field development migrated to 10-acre bottom-hole spacing with surface locations consisting of three to four wells per pad. Historically, pricing pressures dictated the use of conventional mechanical drilling rigs. In recent years, as product prices increased and as well inventory in easily accessible areas became drilled up, the need to drill many wells from a single remote surface location became apparent. These purpose-built rigs facilitate this, plus bring multiple performance improvements, environmental benefits, and well cost reduction to the asset. This paper will be presented by E.S. Kolstad at the 2007 SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 20-22 February 2007.
CIDS to Orlan: Transformation and Startup of Sakhalin's Ice-Resistant Drilling Platform
Authors: Higgins Anthony M. , Zuskov Boris , Zande Paul Vande 
Published: December 2007

Abstract
The drilling and operating environment offshore Sakhalin Island is one of the most challenging in the world. The combination of extreme weather, ice-pack conditions, remote location, and world-class, three-dimensional (3D) extended reach drilling (ERD) objectives demands a highly specialized drilling and production installation to realize success. The milestones and learnings attained during the conversion and start-up of the former Glomar Beaufort Sea I (CIDS: Concrete Island Drilling Structure) to its current status as the Orlan Drilling and Production platform are detailed in this paper.
Starting with the platform redesign and transformation through the commencement of drilling operations, the project has successfully met and overcome multiple challenges. The original CIDS facility, built in the 1980's, was designed to drill a maximum of three arctic exploration / appraisal wells. The basic structure and platform modules were upgraded to provide the full complement of fifth generation drilling elements needed to support a remote, offshore operation in the seismically active, Russian arctic environment. The Orlan platform is now capable of continuous operations throughout the harsh storm and ice-pack conditions of offshore Sakhalin Island. The drilling systems enable efficient completion of world-class, 3D ERD-length wells and the production facilities will allow for year-round oil and gas delivery. The upgrade yielded substantial savings over the design and construction of a new gravity-based structure (GBS) and fifth generation rig.
Drilling operations on the Orlan platform began at the start of the 2005 winter and ice season. Marine and aviation logistics support functions were stretched to their working limits in order to sustain continuous operations. The highly-competitive local labor market and difficult travel conditions impacted personnel continuity. Extreme weather conditions affected the offshore working environment and heating systems.
Despite the challenges, the upgrades were completed safely, the platform was delivered in a timely fashion, and optimizations continue to be realized. The successful conversion and start-up of the Orlan drilling and production platform illustrates the unwavering focus the Company places on safety, flawless execution and timely application and deployment of technology and personnel.