bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well Design for Drilling Through Thick Evaporite Layers in Santos Basin—Brazil
Authors: Poiate E. , Costa A. M. , Falcao J. L. 
Published: December 2007

AbstractThe presence of evaporite sections in prospects for oil or gas exploration is, in itself, a factor that increases the probabilities of success in the area due to favorable conditions for the hydrocarbons generation and trapping. However, many operational problems such as stuck pipe and casing collapse have been reported by the industry when drilling through those salt layers.Historically, in the Campos Basin - Brazil, several deep wells have been drilled through thick salt intervals. Up to the 90's, the lack of reliable ways to predict salt behavior at high temperatures and high differential stresses led to very high drilling costs and even loss of wells.1This paper presents a methodology for drilling fluid and casing design and drilling strategy for drilling at great depths through thick salt layers. The numerical simulation to evaluate the creep behavior of salt rocks (halite, carnalite and taquihydryte) submitted to high differential stress and high temperature was done through the application of an in-house finite element code developed.Results obtained by the numerical simulations in prospect with 2000 meters thickness of different evaporite rocks with high creep rate was used to predict the evolution of the well closure with time for various drilling fluid and analyze several technically feasible alternatives to drilling strategy. The casing design was accomplished with several failure scenarios of cement the casing/borehole annulus through the salt, and drilling fluid in annulus to determine the nonuniform loading and timing of salt loading on well casings deformation or ovalization. The casing was design to be capable of supporting high creep rate of carnalite and taquihydryte.
Achieving Statoil Visund's World Record Reach With Intermediate Size Drillpipe—A Case History
Authors: Ogilvie W. , Chandler R. B. , Devlin A. , Kile H. , Rolfsen K. , Eilertsen Ø. 
Published: December 2007

Abstract
Statoil ASA's Visund project is operated from a floating installation located in the Tampen area of the Norwegian North Sea. The Visund field has been developed through 16 subsea-completed wells over the past six years. Recently, Statoil ASA set a world record by drilling the longest reach well from a floating installation. The well A-6HT2 (A-6) was drilled to a measured depth of 9,082 meters, 819 meters deeper than the Visund A-22 AHT2 (A-22) well. A-22 previously held the record. In addition to setting a new world record, well A-6 was finished ahead of plan, within budget and set a Visund record for the fastest spud to total depth ERD well with an average rate of penetration (ROP) of 108 meters per day.
Compared to the A-22 well, a key technology used on A-6 was a full-length, intermediate sized 5 7/8-inch drill string. Well A-22 used a conventional tapered drill string with several different drill pipe sizes. Some of the achievements noted with the intermediate sized pipe were improved running and handling speed, reduced handling tool inventory and maintenance, reduced surface pump pressure and maintenance, reduced drill string weight and a large cost benefit from improved drilling speed. Achieving this record reach has enabled Statoil ASA to hit targets from the floating installation that were previously thought unreachable, reducing the need to develop the field with less economical mobile floating rigs and offset subsea developments.
Since its introduction in 1999, the design and operational benefits of intermediate sized 5 7/8-inch drill pipe have been presented in many publishing's.1,2 Few have focused on specific case histories with documented performance improvements. This paper will present a case history of 5 7/8-inch drill pipe in use and how it allowed a world record to be set. A novel method for equivalent circulating density (ECD) reduction in the troublesome 8 1/2-inch hole section will also be presented.
Liner Hanger Trapped Annulus Pressure Issues at the Magnolia Deepwater Development
Authors: Eaton L. F. , Reinhardt W. R. , Bennett J. S. 
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 are completed using dry trees from the TLP.
The production casing for each well consists of an 8.062 in. liner set near the base of a 10.75 in. liner. The 10.75 in. liner is tied back to the subsea wellhead. The subsea wellhead is tied back to the TLP with an 11.75 in. production riser.
To minimize heat loss in the produced fluid above the mudline, the production riser x tubing annulus is filled with low-pressure nitrogen. Completion brine is left in the well below the mudline. Two of the eight wells did not have cement behind the 10.75 in. liner hanger polished bore receptacle (PBR), leaving a trapped annulus.
Results from annular pressure build-up programs and finite element analysis (FEA) of the PBR tieback stem configuration, indicated that the combination of increased annular pressure due to temperature heat up during production along with the reduced hydrostatic pressure of the nitrogen in the annulus could cause a collapse failure of the 10.75 in. liner hanger PBR. Since the tieback string had been run and cemented, it was not possible to access the annulus behind the liner hanger PBR by conventional means.
A number of potential solutions to address the problem were considered: scab liner, expandable casing, perforate and squeeze annulus, low heat-transfer gel instead of nitrogen, and high-density brine. This paper will discuss the analysis of the potential collapse issue of the liner hanger PBR, the potential solutions, and implementation of the solution on the actual wells.
Experimental Study on Cuttings Transport With Foam Under Simulated Horizontal Downhole Conditions
Authors: Chen Z. , Ahmed R. M. , Miska S. Z. , Takach N. E. , Yu M. , Pickell M. B. , Hallman J. 
Published: December 2007

Abstract
The use of drilling foams is increasing because foams exhibit properties that are desirable in many drilling operations. A good knowledge of cuttings transport efficiency under downhole conditions is essential for safe and economical foam drilling. Previous cuttings transport studies with foam are limited to low pressure and ambient temperature conditions; no experimental study has been conducted under downhole (i.e. elevated pressure and temperature) conditions. This paper presents an experimental study of cuttings transport with foam in a horizontal annulus under simulated downhole conditions.
Experiments were conducted to determine the effects of polymer additives, foam quality, flow velocity, temperature and pressure on foam cuttings transport. Experiments were carried out at elevated pressure (100 psi to 400 psi) and temperature (80°F to 170°F) conditions in a unique full-scale flow loop with a 73-ft long test section (5.76" × 3.5" concentric annulus). A field-tested commercial foam system consisting of surfactant (1% v/v) and Hydroxylethylcellulose polymer (HEC) was used in the experiments. Three different polymer concentrations (0.0%, 0.25% and 0.5% v/v) were tested. Foam quality was varied from 70% to 90%.
During a test, cuttings were injected continuously to the flow loop until a steady state condition was established in the test section. In-situ cuttings volumetric concentration in the test section was determined using nuclear densitometers, load cell measurements, and by weighing cuttings flushed out of the flow loop. Test parameters recorded during the experiments were: liquid and gas injection rates, cuttings weight in injection and removal towers, mixture density, friction pressure loss, pressure and temperature in the annulus.
Two flow patterns, stationary cuttings bed and fully suspended flow, were observed during the cuttings transport tests. The flow pattern depends on polymer concentration, foam quality and annular velocity. Annular flow velocity, foam quality and polymer concentration all affect cuttings transport efficiency and frictional pressure loss. This paper will help to better design foam drilling and cleanup operations.
Re-engineering Barge Drilling for Deep Miocene HP/HT Frontiers in a Mature Basin
Authors: Husband F. J. , Bitar G. , Begnaud T. , Petticrew T. 
Published: December 2007

Abstract
Although considered a mature exploration area, the United States continues to attract exploitation of developed gas fields due to its well developed downstream infrastructure. However, natural gas production from major US basins is expected to fall below U.S. demand in the near term. Deep Miocene gas exploration programs in the Gulf of Mexico have emerged to exploit this supply shortfall. While attention has focused on jack-up rig designs for shallow water offshore prospects in this market, recent discoveries lie in 18 feet or less of water in Louisiana; the traditional operating area of the conventional swamp barge fleet.
Penetration rates, hole stability, and mud properties are key well construction parameters for both deepwater and deep gas projects, and lessons learned apply to both areas of operation. Deep gas targets have comparatively more compacted formation, higher temperatures, and low margins between flowing wells and lost returns, thus well control is a driving factor in well design. This paper describes the re-engineering of a conventional deep drilling barge rig to deliver a new generation high pressure/high temperature/high flow barge rig designed for increased reliability and specification for deep gas drilling programs in the US Gulf Coast region. Upgrading the main power and distribution systems and high performance pump configuration are discussed as well as resulting auxiliary system modifications.
Results of initial prospects drilled with this modified rig (Rig 76 B) in south Louisiana are presented, describing how upgrades on the rig impacted drilling performance. Safety and environmental results, hydraulics optimization, high pressure mud circulating system performance, and trouble shooting new components are included. The successful integration of drilling technologies including real time formation evaluation, bottomhole assemblies and performance drilling is discussed from the rig perspective. Finally, a check list of potential areas for improving the full potential of the rig in the market is provided to expand the application as more challenging drilling prospects are evaluated for technical and commercial feasibility.
Use of Real-Time Data at the Statfjord Field Anno 2005
Authors: Milter J. , Bergjord O. G. , Høyland K. , Rugland B. 
Published: December 2007

Abstract
The Statfjord Field has produced about 635 million Sm3 (four billion bbl) of oil and exported 68 billion Sm3 of gas since the production start in 1979. Currently, the field is in its tale production, producing at an oil rate of approximately 20,000 Sm3/d, which is about 17 per cent of plateau production rate. Improved recovery and thereby extended production life of the Statfjord Field is now to be obtained by changing the drainage strategy from pressure maintenance to depressurisation. About three million working hours are planned for in connection with the upgrades required to extend the lifetime of the Statfjord Field by approximately 10 years. The production will continue and be optimised during the upgrading and changed drainage strategy.
Real time data transfer from offshore to land enables support of drilling, well intervention and production operations in an efficient manner. New work processes were required in order to facilitate remote support as well as quality control of production logging, measurement while drilling, drilling parameters, geology structures, well completion, process adjustments and production optimisation. In addition, onshore engineering support results in a much better utilisation of engineering resources. Visualisation in onshore/offshore meetings (twice a day) has enhanced a common understanding and made the work process integrated. Careful planning of adjusted work processes and making an energising involved personnel were the most important issues in order to achieve results and drive the changes.
The results so far are successful and the conclusion is a continuation of the project and an expansion of the involved professional disciplines to gain increased quality and time efficiency of the offshore operations.
A Comprehensive Expert System for Diagnosing and Assessing Formation Damage
Authors: Garrouch A. A. , Malallah A. H. , AlEnizy M. M. 
Published: December 2007

AbstractAn expert system capable of diagnosing the potential of formation damage caused by clay swelling, fines migration, inorganic scale deposition, and organic scale precipitation was developed and implemented. In this manuscript, we present results for the expert modules pertaining to asphaltene precipitation and asphaltic sludging. These modules estimate heuristically the potential for asphaltene precipitation, and for asphaltene sludge due to acidizing.Rules of thumb pertaining to asphaltene precipitation caused by solubility incompatibility between crude and solvent were collected. Membership functions to fuzzify these rules were constructed. The asphaltene module is capable of estimating the potential of asphaltene precipitation for a wide range of phase-behavior reservoir conditions, and for a much wider range of live and stock-tank crude compositions than what can normally be handled by a human expert. The acid sludge module makes its judgment based on factors such as acid strength, acid type, solvent preflush, iron control additives, Ferrous and Ferric ion concentrations, mutual solvent concentration, corrosion inhibitor type, and surfactant types used. A model has been formulated to predict the amount of asphaltene sludge that is likely to form as a consequence of crude-acid contact.A graphical user interface using various templates for data input and modules output has been built to make the expert system user friendly. The expert modules have been validated using a range of field data. This expert system gives the advantage of automating the diagnosis process pertaining to formation damage.
When and Where Relative Permeability Modification Water-Shutoff Treatments Can Be Successfully Applied
Authors: Sydansk R. D. , Seright R. S. 
Published: December 2007

AbstractThis paper provides guidance on when and where relative- permeabiliy-modification/disproportionate-permeability- reduction (RPM/DPR) water-shutoff (WSO) treatments can be successfully applied for use in either oil or gas production wells. When properly designed and executed, these treatments can be successfully applied to a limited range of oilfield excessive-water-production problems. When these treatments are applicable, they may be placed using bullhead injection (not requiring mechanical zone isolation)—a very favorable feature. However, there are a substantial number of limitations and possible pitfalls relating to the successful application of RPM/DPR WSO treatments. First-time application by an inexperienced operator should be considered a somewhat high-risk undertaking. In order to successfully treat unfractured production wells (i.e., radial flow through matrix rock into the well) that are fully drawn down, the oil and water zones should not be in pressure communication and the oil- producing zone(s) must be producing at 100% oil cut (dry oil). When treating unfractured and multi-zoned production wells that are not fully drawn down, the well's long-term oil- production rate can be increased if the post-treatment drawdown is increased substantially. Treatments that promote short-term (transient) decreased water/oil ratios can, in principle, be applied to many unfractured production wells (that are not totally watered out) in matrix rock reservoirs. However, these latter treatments must be custom designed and engineered on a well-by-well basis. Furthermore, for most wells, the performance and the economics of such transient WSO treatments are generally marginal. An attractive application of RPM/DPR WSO treatments is the use of robust pore-filling gels in the matrix reservoir rock that is adjacent to a fracture(s) when oil and water is being co-produced into the treated fracture.
Optimizing Disproportionate Permeability Reduction
Authors: Seright R. S. 
Published: December 2007

Abstract
An idealistic goal of water shutoff technology is identifying materials that can be injected into any production well (without zone isolation) and will substantially reduce the water productivity without significantly impairing hydrocarbon productivity. Although many polymers and gels reduce permeability to water more than to oil or gas, several factors currently limit widespread field applications of this disproportionate permeability reduction property. First, adsorbed polymers and weak gels (suspensions of gel particles) show large variations in performance. Second, in unfractured wells (i.e., radial flow into porous sand or rock), the oil residual resistance factor, Frro, (permeability reduction factor) must be reliably less than 2. Third, adsorbed polymers and weak gels reduce permeability by greater factors in low- permeability rock than high-permeability rock.
Strong pore-filling gels were investigated to overcome these limitations. For porous media with pre-gel kw (at Sor) ranging from 120 to 6,500 md, one Cr(III)-acetate-HPAM gel (with 0.5% HPAM) consistently reduced kw to about 0.24 md (ranging from 0.12 to 0.37 md). In contrast, in Berea sandstone with kw (at Sor) ranging from 222 to 363 md, a weak gel (with 0.18% polymer) exhibited a much wider range of post-polymer kw values—from 0.75 to 202 md. Thus, strong pore-filling gels can provide greater reliability and behavior that is insensitive to the initial rock permeability.
With sufficient oil throughput, pore-filling gels dehydrate, thus increasing permeability to oil. Several gel formulations provided water residual resistance factors greater than 2,000 and ultimate Frro values of 2 or less. These results provide hope that our current approach will identify gels that can successfully and reliably treat either fractured or unfractured production wells without zone isolation. Significant oil throughput was required to achieve low Frro values, suggesting that gelant penetration into porous rock must be small (a few feet or less) for existing pore-filling gels to provide effective disproportionate permeability reduction.
Air Injection and Waterflood Performance Comparison of Two Adjacent Units in Buffalo Field: Technical Analysis
Authors: Kumar V. K. , Gutierrez D. , Moore R. G. , Mehta S. A. 
Published: December 2007

Abstract
Buffalo Field covers a large area on the southwestern flank of the Williston Basin, in the northwest corner of South Dakota. In 1987, 8440 acres of the field were divided into two units to initiate improved oil recovery (IOR) operations with two different methods: air injection and waterflooding. After collecting 18 years of production history a comparison has been made between the two projects to determine the relative success of both units.
This paper addresses the technical performance of both projects in terms of incremental oil recovery, estimated ultimate recovery and incremental recovery per volumes of fluid injected. Ultimate primary recovery was estimated using conventional decline curve analysis on individual wells. Ultimate recovery was estimated by extrapolation of the current performance of the units assuming the same actual development scheme and operating strategies. Technical advantages and limitations of both IOR methods as applied in this field are also discussed.
Throughout the years, the West Buffalo Red River Unit (WBRRU) under air injection has shown a significantly superior performance over its "twin" West Buffalo "B" Red River Unit (WBBRRU) being waterflooded. Quicker production response to injection, higher production rates and higher incremental recovery are some of the advantages shown by air injection as an IOR method in this field.
This case study clearly shows the technical viability of air injection as an efficient method of improved oil recovery particularly in deep, high pressure, low permeability reservoirs where water injectivity is limited and other recovery processes become uneconomic.
The myth of air injection as a high risk, unsuccessful operation is shown to be invalid; and instead, it proves to be a feasible way to unlock oil accumulations.
Correlating Gel Rheology with Behavior during Extrusion through Fractures
Authors: Wang Y. , Seright R. S. 
Published: December 2007

Abstract
In many successful conformance control treatments, large volumes of gels were extruded through fractures during placement. The pressure gradient for gel extrusion depends strongly on fracture width and gel composition. Extrusion experiments directly measure gel properties in fractures, but they are both expensive and time-consuming. In this work, we investigated whether using rheology measurements to assess gel properties in fractures might prove a good substitute for the extrusion experiments, at a much more reasonable cost. The rheology behavior of the gels tested showed a strong parallel to the results obtained from previous gel extrusion experiments. However, for a given aperture (fracture width or plate-plate separation), the pressure gradients measured during the gel extrusion experiments were much higher than anticipated from rheology measurements. Extensive experiments established that wall slip and first normal stress difference were not responsible for the pressure gradient discrepancy. Steady shear and oscillatory shear data were collected with a rheometer using both smooth and rough parallel-plate geometries and employing various gap heights. Wall-slip effects were present with smooth plates but negligible with rough plates.
To explain the discrepancy, we noted that the aperture for gel flow (for mobile gel wormholing through concentrated immobile gel within the fracture) was much narrower than the width of the fracture. Considering the shear-thinning properties of the gels, two models were developed using shell momentum balances. The first model explained why the pressure gradient for gel extrusion varied inversely with the square of the fracture width rather than inversely with fracture width. In particular, the relationship depends on the power-law index of the material. The second model correlated pressure gradient, shear stress, flow rate, and shear rate to bridge the gap between gel rheology in fractures versus in a rheometer.