bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geological Modeling Using Azimuthal Density Neutron Images: A Case Study in Khamilah Field, Northwest Oman
Authors: Amer A. , Riyami K. A. , Rowland B. , Van Wijhe L. , Al Hadhrami M. 
Published: December 2007

Abstract
When drilling the first well in a new prospect, understanding the geological setting is a challenge, especially with high uncertainty from seismic information. Working with other available data, such as borehole images and openhole logs, is critical to reduce uncertainties. One type of data that can help the operator reduce these uncertainties at the earliest stage in the well construction is logging while drilling (LWD) data.
The horizontal section of well Khamilah-1 was drilled with a 4.75-in. bit. With this borehole size, it is not possible to obtain resistivity images at the bit, as is commonly done in 8.5-in.-diameter wellbores to determine bedding dip and fracture occurrence. Recent work with 16-sector LWD azimuthal density neutron images obtained in 4.75-in. horizontal wellbores has proven that interpretation of these images is effective in determining structural dip and fracture occurrence in the horizontal wellbore. These data are used with LWD logs to compute a 2D geological model. The 4.75-in. tool azimuthal density neutron images are a valuable aid in guiding the wellbore while drilling and in building 3D models of the reservoir.
The model constructed for Khamilah-1 using azimuthal density neutron images and LWD logs identified two structural zones (including a fold) and one normal fault.
This case study illustrates that a 2D geological model is critical for accurate structural and geological definition of the wellbore environment, especially during the early exploration stages when data are limited and uncertainties are high. The procedures developed and applied in this work are not restricted to horizontal wells; they can also be applied to vertical and deviated wells.
Beryl Field: Extracting Maximum Value from a Mature Asset Through the Evolution of Technology
Authors: Cutt R. N. , Niznik M. R. 
Published: December 2007

Abstract
The Beryl field was discovered in 1972 and 143 separate penetrations have been drilled from the two platforms. The field is faulted, generating numerous drilling opportunities but also geological uncertainties. 3D visualization is used to identify/target bypassed oil in the peripheral reservoir sectors. Extended reach/3D designer wellpaths are utilized to intersect ever smaller targets. New formation evaluation/geo-steering concepts like chemical stratigraphic analysis are used to identify target intervals in real-time.
Modified rotary steerable tools are employed in the hard/abrasive Beryl formations. Real-time vibration monitoring is used to optimize drilling performance, which provides a basis for bottom hole assemblies and bit design/selection. Onsite engineers are used to analyze/evaluate real-time torque, drag, vibration, hydraulics, and wellbore stability parameters.
Wellbore stability is a major challenge. A proprietary technique is used to build formation integrity in depleted zones. This enables mud weights critical to provide stability in highly reactive shales to be used. Due to this and the compartmentalized nature of the Beryl field, highly overbalanced drilling is a result. Depleted zones in the Beryl field having pore pressures as low as 1.5ppge/0.17SG have been drilled with up to 5000 psi overbalance (to maintain wellbore integrity).
Reducing the number of trips is a focus to save rig time. PDC bit technology is used in casing mills for a single trip system when exiting from whipstocks during slot recovery operations. Sacrificial bits/motors on production liners are used to eliminate wiper trips. Cemented tubing completions, utilized on water injection wells, achieve cost savings.
Beryl field life was initially estimated to be 20 years, but is now in its 28th year of production. New technology/techniques are added to the drilling toolbox continually, enabling wells which were unthinkable to become common and economical in this mature field.
The Planning and Drilling of Hot Ice #1-Gas Hydrate Exploration Well in the Alaskan Arctic
Authors: Kadaster Ali G. , Millheim Keith K. , Thompson Tommy W. 
Published: December 2007

Abstract
Anadarko Petroleum entered into a cooperative effort in 2002 with the U.S. Department of Energy (DOE) and Maurer Technology Inc., a subsidiary of Noble Drilling, to explore for and production test a Gas Hydrate zone. The purpose of the project was to build on previous and ongoing R&D in the area of onshore hydrate deposits to identify, quantify and predict the production potential for hydrates. The plans included the continuous coring and then production testing of a Gas Hydrate well on the North Slope.
The project scope was modified to include the field trial of an onshore Mobile Platform that Anadarko had designed (patent applied for), presented by Kadaster and Millheim¹ at the 2004 annual IADC/SPE meeting in Dallas, Texas.
With this scope modification, the project also became a prototype project for a cost effective and environmentally safer exploration system in the remote reaches of the Arctic and other environmentally sensitive areas, such as the US Rockies or the shallow water estuaries around the world.
While the geological and geophysical analysis were being conducted; the drilling / coring systems and the drilling rig were selected; the modular platform systems commissioned; the drilling and platform sub-systems tested in simulated and actual arctic conditions, and the potential wellsites permitted.
Field operations commenced in January 2003, suspended in April 2003, resumed in January 2004 and completed in March 2004. The entire Hydrates Stability Zone was cored and analyzed. Although no hydrates were encountered, valuable information and field expertise regarding the hydrate exploration methods, the modular Arctic Platform and the prototype remote exploration systems were gained.
Silicate-Based Fluid, Mud Recovery System Combine to Stabilize Surface Formations of Azeri Wells
Authors: Alford S. E , Asko A. , Campbell M. , Aston M. S. , Kvalvaag E. 
Published: December 2007

Abstract
Historically, the surface holes of the wells in the West Azeri field of the Caspian Sea were drilled conventionally with seawater and gel sweeps. However, seawater destabilized the highly reactive soil formations in the surface interval, resulting in unacceptable movement of the 20-in. casing. Further examination identified mechanical and chemical destabilization of the reactive shallow soils as the root causes of this instability.
This paper describes the application of a silicate-based drilling fluid system1, 2, 3, 4, 5, 7, 8in tandem with a unique Mud Recovery System (MRS) that combined to stabilize the problematic formation and allowed for the successful setting of the 20-in. casing without the lateral movement experienced in offset wells.
The operator conducted laboratory tests to identify possible fluid alternatives that would provide the necessary chemical stability to provide support for the template and casing. The laboratory investigation considered conventional SBM, glycol/polymer/KCl and silicate/polymer/KCl inhibitive water-based fluids, and a KCl/NaCl/high-performance water-based mud (HPWBM) as possible alternatives. The oil-based, HPWBM and silicate systems demonstrated excellent chemical stabilization. Offshore discharge restrictions negated the use of oil-based drilling fluids if the MRS was used. The HPWBM provided an alternative but logistics eliminated it from the initial consideration, thus opening the door for the first-time use of the silicate-based system in the Caspian Sea.
The authors also review the application of the MRS system that utilized the rig pumps to deliver the fluid down the drill pipe and up the annulus to specially designed equipment on the sea floor. The latter used a sub-sea disc pump to transfer the fluid to the surface for conventional solids processing and maintenance. This technique provided a dual gradient to control the equivalent circulating density.
Three field tests were conducted to determine the best fluid and mud weight for use in drilling the surface holes for the operator's template in the West Azeri field. The first test with the MRS unit used a conventional silicate/polymer/KCl system; the second test employed a synthetic-based drilling fluid with a pin-connector and a riser. A third trial utilized the silicate/polymer/KCl system with increased concentration levels of silicate and KCl and a higher mud weight. The authors will review the fluid planning, the performance of the three field trials, and the results which have been implemented into an ongoing field development program.
Oil-Based Mud Micro-Imager (OBMI) Application in Sangatta: A Field Case Study
Authors: Sembiring P. , Agustinus S. R. , Bashir N. , Danardatu A. H. 
Published: December 2007

Abstract
PT Pertamina (Persero) DOH Kalimantan has embarked on the development of the almost virgin South Eastern area of Sangatta Field. The wells test results showed additional untapped reserves in this part of the field encouraging further development of this area. Oil based mud system is used in the current development drilling of this area, in order to enhance drilling performance and borehole stability, necessitated a change of the logging program. In addition to the basic logging suites and due to the complexity of the remaining reservoir facies spatial distribution, PT Pertamina DOH Kalimantan acquired Oil Based MicroImaging (OBMI) data to help guide in the development of this virgin part of the Sangatta field.
Good quality Oil Based MicroImaging data were obtained showing for the first time detailed sedimentary and structural bedding and providing reliable structural and sedimentary bedding dip data in OBM environment allowing geologic facies analysis and accurate spatial distribution interpretation of the reservoir facies. In this Sangatta deltaic environment of deposition the OBMI image data along with the conceptual geologic model allowed very good control in mapping the architecture of the reservoir facies.
In this joint paper, case study of OBMI data will be presented demonstrating the methodology and results of comprehensive approach to sedimentological interpretation of borehole image data using the OBMI and relevant other geological data.
Extended Reach Drilling (ERD) Technology Enables Economical Development of Remote Offshore Field in Russia
Authors: McDermott J. R. , Viktorin R. A. , Schamp J. H. , Barrera M. W. , Fleming J. M. , Keller S. R. 
Published: December 2007

Abstract
Advanced extended reach drilling (ERD) and completion technologies were successfully tested in a challenging remote Russian Far East location to prove feasibility of land based development for the offshore Chayvo field. Chayvo is located 8-11 km off the eastern coast of Sakhalin Island in the Sea of Okhotsk. Development plans using offshore platforms were marginally economic because of arctic design and operating conditions.
Two ERD wells were drilled in a pilot program to measured depths of 9,375 m and 10,182 m. Horizontal displacements of the wells were 8,419 m and 9,246 m at a true vertical depth (TVD) of 2,613 m. These first two Chayvo ERD wells represent record wells for ExxonMobil and are currently the 7th and 4th longest ERD wells in the world. Other highlights include the first 13-5/8 in. casing installation using "mud-over-air" flotation and record coiled tubing runs.
Absence of drilling data between the land-based surface location and the reservoir made planning Chayvo ERD wells difficult. ERD well design was based on a systematic planning approach through study of local Russian and worldwide geometric offset wells and application of ExxonMobil proprietary technologies (Integrated Hole Quality/Quantitative Risk Assessment). A comprehensive directional plan was developed to successfully intersect the reservoir target objective at a precise depth and location. Wells were drilled using rotary steerable systems (RSS) and polycrystalline diamond cutter (PDC) bits. Formation evaluation was achieved using logging while drilling (LWD) tools from surface to total depth (TD).
Multiple challenges including tight schedules, international logistics and adverse weather conditions were overcome prior to spudding the first well. The team quickly adapted to actual well conditions (i.e. fracture gradients, wellbore stability, and high torque) while drilling. The now proven feasibility of ERD technology at this location will help make a once marginal "high-cost" project economic.
A Pseudo-Black-Oil Method for Simulating Gas Condensate Reservoirs
Authors: Wang S.-W. , Harmawan I. 
Published: December 2007

Abstract
A method was developed to estimate the composition of heavy end by matching MDT pressure gradient when downhole sample or reliable recombined surface sample is not available. After adjusting the heavy end or C7+ composition, an equation-of-state was used to match (1) MDT pressure gradient from calculated gas density, (2) dew point, (3) surface condensate yield, and (4) API gravity of condensate. The fine tuned equation-of-state was then converted into a pseudo black oil PVT table. This method allows reservoir engineers to study production from retrograde gas condensate reservoirs without using equation-of-state to handle complex phase behavior and commingled production from multiple reservoirs.
Three examples are included to illustrate the proposed method. The first two examples give detailed description of step by step procedures. The third example incorporates a 3D reservoir simulation model and a pipeline to form an integrated model. The reservoir model consists of two separate reservoirs to be produced by two subsea wells, which are linked to a surface pipeline tied back to West Seno FPU. The advantages and disadvantage of this method are discussed at the end of this paper.
Productivity Impact from Matrix Stimulating Thick Intervals Using a Nondamaging Self-Diverting Acidizing System: A Northwestern Kazakhstan Case Study
Authors: Bitanov A. A. , Nadezhdin S. V. , Adilgereev R. S. , Zhaniyarov S. U. 
Published: December 2007

AbstractA carbonate formation in northwestern Kazakhstan is a challenging environment for acid stimulation because of its thick intervals, heterogeneity, and natural fractures. From production log interpretation, it was observed that the layers were not being depleted uniformly because of the difference in flow properties, resulting in an uneven distribution of flow from perforations. The challenge was to achieve a more uniform flow profile.The paper will show the effect a self-diverting acidizing system has brought to field productivity when benchmarked to historical treatment methodologies. A net gain of 1900 cubic meters per day (m[3]/d) was realized as a result of the treatment campaign on 17 wells. The benefits to reservoir management from treating the heterogeneous long intervals and achieving uniform flow profiles will be discussed in detail through a comprehensive review of pre- and post-treatment production profile logs.The new treatment methodology employed has been used in freshly drilled wells. The paper will discuss the effect on productivity as well as how the methodology has been incorporated into subsequent field development planning.
A New Type of Super-Adsorption, High-Desorption Scale Squeeze Chemistry: Doubling Treatment Life On Miller Wells
Authors: Wylde J. J. , Williams G. D. M. , Careil F. , Webb P. , Morris A. 
Published: December 2007

Abstract
The scaling potential of Miller wells is widely accepted as being perhaps the severest in the North Sea, if not the world. This creates a unique chemical challenge, the aim of which has always been to extend the lifetimes of scale squeezes across all the wells. A new scale inhibitor has been deployed which has achieved this goal. The chemistry in question is a novel polymeric chemistry which contains multiple functional groups, including phosphorus tagging.
Two years were spent developing and extensively testing the chemical in the laboratory, and the resulting product was assessed against those submitted as part of an industry wide search. The new chemical is now deployed on all Miller wells and performance has been beyond all expectations. Two wells have already seen a doubling in the treatment lifetimes resulting in thousands of barrels of incremental oil production. This is particularly important for Miller, where total operational efficiency is paramount as the cessation of production date approaches.
This paper documents some of the initial laboratory work involved with the development of the new chemical but mainly dwells upon the field treatments on Miller wells A14(19), A17(04), A18(32), A21(02), A25(29) and A26(08), covering almost 50 squeeze treatments. The paper goes on to describe the management strategy as well as the approach adopted to determine the limit of the squeeze life. In every case the chemical has outperformed the incumbent in terms of barrels of water protected and total scale inhibitor efficiency. This outcome is unprecedented on Miller: No other new chemical has delivered such a dramatic and significant improvement in scale control economics.
Innovative, Integrated, and Cost Effective Chemical Management on the Miller Platform
Authors: Wylde J. J. , Williams G. D. M. , Careil F. 
Published: December 2007

Abstract
The BP operated Miller field poses a unique chemical challenge as it has, arguably the harshest oilfield scaling regime in the North Sea, if not the world. Some 3 million litres of chemical are consumed each year and the management, supply, use and performance of every aliquot of chemical is imperative to see Miller through to its planned cessation of production (COP) in December 2006.
The Miller field is a mature North Sea asset and produces a potential of 80,000 bbl of water with its 16,000 bbl of oil every day. The unique challenge posed by Miller is that the produced water contains very high concentrations of scale forming components combined with a very high corrosivity potential. Chemicals are routinely deployed to control scale, corrosion, emulsions, foam, biological fouling and hydrates.
Two major step changes have occurred in the past 12 months that have delivered significant improvement to chemical management processes. The first is the use of a novel, best-in-class scale inhibitor chemistry. Two years were spent in an industry wide search as well as developing and extensively testing the chemical in the laboratory. The new chemical is now deployed on over 75% of the Miller wells. The longevity of scale prevention treatments has been doubled on some wells, when compared to the incumbent products.
Critical Evaluation of the Ensemble Kalman Filter on History Matching of Geologic Facies
Authors: Liu N. , Oliver D. S. 
Published: December 2007

Abstract
The objective of this paper is to compare the performance of the ensemble Kalman filter (EnKF) to the performance of a gradient-based minimization method for the problem of estimation of facies boundaries in history matching. EnKF is a Monte Carlo method for data assimilation that uses an ensemble of reservoir models to represent and update the covariance of variables. In several published studies, it outperforms traditional history matching algorithms in adaptability and efficiency.
Because of the approximate nature of the EnKF, the realizations from one ensemble tend to underestimate the uncertainty especially for problems that are highly non-linear. In this paper, the distributions of reservoir model realizations from 20 independent ensembles are compared with the distributions from 20 randomized maximum likelihood (RML) realizations for a 2D water-flood model with one injector and four producers. RML is a gradient based sampling method that generates one reservoir realization in each minimization of the objective function. It is an approximate sampling method, but its sampling properties are similar to Markov chain Monte Carlo method (McMC) on highly nonlinear problems and relatively more efficient than the McMC.
Despite the nonlinear relationship between data such as production rates and facies observations, and the model variables, the EnKF was effective at history matching the production data. We find that the computational effort to generate 20 independent realizations was similar for the two methods, although the complexity of the code is substantially less for the EnKF.
Assessment of Rigless Water Shutoff Using through-Tubing Bridge Plug in a Large Onshore Oil Field in Saudi Arabia
Authors: Al-Ghasham Y. Y. 
Published: December 2007

Abstract
A large onshore oil field in Saudi Arabia is supported by peripheral water injection that started 40 years ago. Parts of the field are becoming mature with increasing water production. This poses a challenge as well production is declining and/or, in some cases, ceasing to flow as water cut increases, leaving in-place oil potential that needs to be recovered. Increased water production has another side effect of increasing operating cost to handle and recycle unwanted additional produced water. To reduce water production and reactivate the dead wells, several options were implemented, including facilities operational changes, workovers, and rig-less chemical and mechanical techniques.
One of the easiest and most cost-effective techniques that has been used in the field to reduce water production is the application of the rig-less Through-Tubing Bridge Plugs (TTBP). This paper presents 15 years' experience of the application of TTBP in vertical open and cased holes as well as slightly deviated wells. Data were reviewed for more than 130 wells that had water shutoff jobs using TTBP. The paper discusses results and factors, and reservoir as well as completion parameters that contribute to the success of this rig-less water shutoff technique. These factors include permeability thickness and productivity index, well completion, very high permeability intervals, reservoir pressure, tight porosity intervals, and the flowing wellhead pressure. Discussion of the economics of the application is also presented.
Smart Completion Design With Internal Gas Lifting Proven Economical for an Oil Development Project
Authors: Jin L. , Sommerauer G. , Abdul-Rahman S. , Yong Y. C. 
Published: December 2007

Abstract
An oil acceleration project in an offshore oil field in Brunei Shell requires two oil wells to produce oil via an existing 80 bara (HHP) gas pipeline to a platform. Acceleration of the 2 wells will result in: Accelerated oil production from the oil rims.Acquisition of additional reservoir data for further field development optimization.
This paper will discuss the technical details on the following work: Evaluate the initial production against HHP (8 MPa) in a commingled mode from 3 oil zones.Internal gas mixing (lifting) using source gas from a gas zone. The optimized gas injection rate, downhole choke size have been selected through modeling.Completion designs for the two wells to realize the commingled production with internal gas lifting and enable the evaluation and production testing of each individual zone for reservoir appraisal and reservoir management purpose.
A smart completion design was proposed. It comprises of: Inflow Control Valves (ICV) for surface controlling of production from each zone,Down-hole temperature and pressure gauges for monitoring each individual zone,A hydraulically controlled down hole choke to control the inflow of lifting gas from the gas zone. Based on the study, the range of choke sizes from 2/64" to 60/64" was chosen,Cased hole expandable sand screens (ESS) with extension pack and/or wire wrapped screens (WWS) in open hole sections for sand control,All the control and monitoring can be conducted real-time remotely to minimize the intervention in an unmanned platform.
The intelligent design is a key enabling technology to economically produce small oil rims and maximize liquid recovery, thereby increasing the value of the overall field development. The project exceeded the group economic criteria and has been approved.