bluuebunny/crossref_metadata_2025 huggingface dataset:
Underbalanced Coiled Tubing Drilling Update on a Successful Campaign
Authors: Pruitt Randal , Leslie Charlie , Smith Bruce , Desplain Olivier , Kavanagh Tom , Woolham Tony , Baker Allistar Law , Christou Nick , Borling Daniel
Published: December 2007

Located in the Emirate of Sharjah, United Arab Emirates, the Sajaa onshore gas field is a Thamama Group limestone reservoir ranging from 11,000 to 13,000 feet true vertical depth (3350 to 3960 meters). Bottomhole temperature ranges from 260 to 310 degrees Farenheight (126 to 154 Celcius) and bottomhole pressure from 1100 to 1900 psi (75 to 129 atmospheres). This paper contains lessons learned from the project to date by the various authors directly involved with this unique and highly successfull Underbalanced Coiled Tubing Drilling project.
Field Proof of the New Sliding Technology for Directional Drilling
Authors: Maidla Eric , Haci Marc , Jones Scott , Cluchey Michael , Alexander Michael , Warren Tommy
Published: December 2007

This work shows how sliding to make a trajectory correction can significantly improve directional drilling with a mud motor and measurement while drilling (MWD) system using a new surface only technology called Slider.

Slider deploys a small robot to interface with the trop drive control panel that automatically rocks the pipe to the right and left following a rigorous analysis of torque by a computer/software that receives the surface torque and stand pipe pressure values as feedback.

Improvements from this sliding technique included the following:

Increasing sliding rate of penetration (ROP) by more than three-fold in some cases. Reducing motor stalls to zero (sometimes seven stalls per slide were recorded for the conventional method on a slide distance that ranged from 5 ft to 15 ft). Reducing time to orient tool face by an order of magnitude. Tool face orientation was obtained in about 1½ to 2 minutes without coming off bottom, as compared to enormous difficulties while trying to do this manually for the larger horizontal departures. Providing a means to release the bottomhole assembly (BHA) when becoming differentially stuck without having to come off bottom and with minimal disturbance to the tool face. Removing the tedious work the directional driller had in "rocking" the pipe, which also reduces the risk of torque breakouts.
Aluminum Alloy Riser Allows for Deeper Drilling on Existing Rigs
Authors: Deul Hans
Published: December 2007

As drilling activities extend further offshore, the need to drill in deeper water increases. When conventional steel risers are used to increase drilling depth, the structural support of existing rig decks must be improved to support the additional weight. These modifications to allow for deeper drilling are both cost-prohibitive and time-consuming. The answer to this industry problem is a riser that is manufactured from an aluminum alloy.

Drilling activity off the coast of Brazil and in the Gulf of Mexico confirms that replacing the conventional line-pipe grades of high-strength steel with a lighter weight aluminum alloy riser allows existing rigs to drill in greater water depths without incurring costly and extensive rig modifications. This paper presents the successful use of aluminum alloy risers onboard the drillship Noble Leo Segerius from January 2003 until the present.

Aluminum alloy riser operations in Brazil since January 2003 have occurred in the following conditions:

Water depth ranging from 1000 m to 1500 m Mud weights up to 11.5 PPG Currents ranging from 2.5 knots at surface to 1 knot at seabed Top tension between 180 T total and 350 T total Rig moves with BOP suspended below the rig on full riser string

Use of the aluminum alloy risers increases an existing rig's potential water depth capability by 40%. Because the existing rig can be outfitted with the lighter-weight and overall less-expensive riser system with no modification to its structure, considerable savings in cost and time are realized along with the increase in water depth capability. With the operation of numerous existing rigs in areas like offshore Brazil and the Gulf of Mexico, the potential for this technology is significant to all who anticipate deepwater drilling.
Managing Pressures During Underbalanced Cementing by Choking the Return Flow; Innovative Design and Operational Modeling as well as Operational Lessons
Authors: Eck-Olsen Johan , Pettersen Per-Johan , Ronneberg Arnfinn , Bjorkevoll Knut S. , Rommetveit Rolv
Published: December 2007

This paper describes operational lessons and the unique simulation model developed for an underbalanced primary cementing of a 7 inch liner at the Gullfaks field in the North Sea.

Due to very small margins it was desirable to avoid pressure changes in the open hole section while circulating the cement. This was obtained by circulating fluids out through a choke that was accurately regulated to maintain constant bottom hole pressure throughout the circulation phase. The fluids in front and after the cement had relatively low density to compensate for the high density of the cement, and choke regulation was crucial before the cement was in place.

The paper describes the operation in detail with special focus on any unexpected events. Measured and predicted pressure curves will be shown, and be analyzed to come up with recommendations on how to carry out similar operations and how to best carry the technology further.

A new transient computer model for cement displacement with dynamic choke regulation has been developed to make it possible to design choke operations accurately.

The results of this paper have applications in any cementing operation where managing bottomhole pressure with a choke is required. The model can be applied in any such operation.

The paper illustrates how to use managed pressure drilling ideas when cementing a well with very narrow pressure margins. The work is considered to be the first step towards managing cementing in combination with managed pressure drilling.
Improved Casing Running Process
Authors: Warren Tommy , Johns Roger , Zipse Dean
Published: December 2007

The conventional casing running process is personnel intensive and requires considerable human contact with the casing. A new casing running system facilitates mechanizing the casing running process. This technology eliminates potential safety hazards, provides assurance that the casing can be run to the intended casing point, offers the ability to ream casing to bottom, reduces personnel requirements for running casing and eliminates the need for a stabber in the derrick.

A portable Casing Drive System* (CDS*) is used to pick up joints of casing from the "V-door", position the casing over the stump in the rotary table, and grip the top of the casing without making a threaded connection. The CDS supports the full torsional and axial load for running the casing and provides the ability to circulate the well at any time to wash and ream to bottom as tight hole or fill is encountered. The top drive provides the rotary power to make-up and rotate the casing.

The new portable casing running system has been used on over 330 wells for thirty-eight operators in nine countries to run more than two million feet of casing of various weights, grades, and connection types with sizes ranging from 4-1/2" to 16". These jobs encompass wells from vertical holes to high angle extended reach wells and include both onshore and offshore applications. The system has been completely mechanized on one Casing Drilling* rig to allow the driller to routinely pick up casing from the pipe racks and make connections with no personnel on the rig floor.
Development of a Gas-Tight External Casing Patch Using Direct Hydraulic Expansion of Standard Casing to Achieve a Permanent Load Bearing Connection
Authors: Gorrara Andrew , Hazel Paul , Tavendale Fraser , Louden Fraser
Published: December 2007

This paper describes the design, development and testing of an External Casing Patch system for installation in an offshore well to repair damaged 9 5/8 inch casing. The casing repair was required to have an effective metal-to-metal seal to hold lift gas injection pressure together with the potential for increasing levels of H2S during the life of the well. The expansion technique used pressures in excess of 20,000 psi to compliantly expand the casing into an external ‘profiled overshot’. The paper also describes the development of a method of generating and controlling such hydraulic pressure downhole.

In addition to theoretical calculations, full scale laboratory testing of the mechanical and the hydraulic sealing properties of the connection have been performed in qualifying the Casing Patch for well deployment. Tests were performed on samples of casing taken from a candidate well to support the theoretical calculations.

A means of making a downhole load-bearing casing connection, with load rating above 200 tons and pressure differential rating of 2,700 psi gas, has been demonstrated. A connection design has been developed that connects directly to a cut casing stub, and therefore does not require back off of casing connections.

The case history presented shows that this technique of connecting tubulars in a well bore has application in remedial work on older or damaged completions, and also as contingency for new wells where a casing string may not reach TD due to differential sticking, swollen shales etc.

Further development of the technique of direct high-pressure expansion is discussed in relation to the design of ultra-deep and slim wells, where the technique employed may broaden the options for completion design, particularly in HPHT wells where the design envelope is challenging.
Development of a Screening System to Identify Deepwater Wells at Risk for Annular Pressure Build-up
Authors: Sathuvalli U. B. , Payne M. L. , Pattillo P. D. , Rahman S. , Suryanarayana P. V.
Published: December 2007

Annular Pressure Build-up (APB) in wellbore annuli is a problem in most deepwater wells. If APB induced loads compromise string integrity, the selection and design of a suitable APB mitigation strategy must be pursued. The calculations required for such analyses can be tedious, since a number of cases to identify key variables and "what-if" scenarios must be evaluated. Though analytical techniques required to evaluate APB and mitigation strategies are well understood, there is a need to perform these calculations quickly and reliably.

This paper discusses the development of a procedure and computational tool to determine deepwater wells at risk for APB. Though the tool structure is simple enough for spreadsheet implementation, it is technically and numerically rigorous. The role of the tool is illustrated with a case study where one or more mitigation strategies are necessary for well integrity. Details required to build such a tool, i.e. assemble the matrix of APB equations, develop quantitative models of mitigation strategies, and, most importantly, create a mathematical representation of a wellbore for use in the APB algorithm, are presented in the appendices. Finally, for the first time, the role of formation elasticity (i.e. the annular boundary conditions) on APB is examined by using equations that treat the formation as an elastic foundation.
Managed Pressure Drilling in Marine Environments – Case Studies
Authors: Hannegan Don M.
Published: December 2007

In around 340 BC, Plato wrote in The Republic, "Necessity, who is the mother of invention." Such is the case of a relatively new offshore drilling technology – Managed Pressure Drilling (MPD), a technology that addresses a litany of issues associated with drilling into "trouble zones".

Drilling-related issues such as excessive mud cost, differentially stuck pipe and resulting well control situations associated with loss circulation issues contribute to defining the necessity for a more efficient drilling technology. A kick-Loss scenario, which may occur when drilling into narrow downhole pressure environments, is another. Drilling-related flat time further indicate a necessity for a technology that enables more precise wellbore pressure management when drilling in marine environments.

These challenges to economic drill-ability apply to a growing percentage of offshore prospects for oil and gas, becoming more troublesome and costly with water depth. These challenges have one thing in common - they all may be addressed to some degree or other with more precise wellbore pressure management. Dictated: A technology that offers more precise pressure management with fewer interruptions to drilling ahead.
Real-Time ECD Simulation and Management Using a Remote Operations Center
Authors: van Oort Eric , Roy Sanjit , Zamora Mario , Toups Bret
Published: December 2007

Economically marginal wells, sometimes critical in their own right, can require tight equivalent-circulating-density (ECD) control just like their expensive HTHP, deepwater, and extended-reach counterparts. Limited budgets or well conditions, however, may preclude use of pressure-while-drilling (PWD) technology. This paper presents a case history where the ability to manage ECDs from within a remote, real-time operations center was tested on an HTHP well in the Gulf of Mexico and subsequently on a low-budget land well in the western United States. Field results demonstrate that it is possible to obtain high-quality ECD information without running PWD tools.

Special hydraulics software run at the operations center provided virtual sensors for equivalent circulating and static densities while drilling, tripping, and running casing. PWD data was available for comparison on both wells, except for the lower intervals of the HTHP well. In the latter well, high formation temperatures exceeded tool limits, so it was necessary to rely strictly on computer simulations for ECD management.

The primary purpose of this paper is to critically review these case histories to help assess the spectrum of opportunities for ECD management from remote operations centers. Field results, operational issues, planning requirements, training efforts, and technical and business drivers are among the topics that will be presented and discussed. Lessons learned and recommendations for future efforts are also included.
Successful Integration of Electromagnetic MWD-LWD Technology Extends UBD Operation Envelope into Severely Depleted Fields
Authors: Wind Jan , Weisbeck Denis , Culen Martin
Published: December 2007

The advantages of electromagnetic (EM) telemetry are not always considered when planning drilling operations. This paper examines the execution and lessons learned from the successful implementation of EM-MWD and LWD technology in an underbalanced horizontal drilling application in the Nimr field in Oman.

Some of the highlights included the highest daily footage drilled underbalanced, enhanced geosteering through the use of real-time LWD information and significant rig time and cost savings when compared with operations using mud pulse (MP) telemetry.

The most significant accomplishment was the demonstration that these wells can be drilled with real-time LWD measurement using standard EM transmission. This is important because it enables underbalanced drilling (UBD) using drillpipe injection with high gas rates, which expands the envelope for UBD operations to severely depleted reservoirs.

Petroleum Development Oman's (PDO) standard UBD practice in depleted reservoirs is to avoid severe formation damage and to use real-time LWD for geosteering horizontal multi-lateral wells in the most productive sections of the reservoir. Prior to this well, the application of UBD was generally accomplished using concentric casing gas injection as it was believed that the only viable means of obtaining LWD information was through mud-pulse transmission.

The application of EM, LWD, and UBD described in this paper represents an important advance in a stepwise progression for improving PDO's ability to exploit mature reservoirs, especially those that are severely depleted.
Running Casing Faster and Safer with Less Cost, Using Existing Rig Crew: A Case Study
Authors: Moussa Noureddine Hadj , Warren John , Roling Ron
Published: December 2007

A new safe and cost effective method of running casing has been employed, using the existing rig crews instead of specialized casing crews. By using a casing running tool connected to a top drive system, the drilling crew can run entire strings of casing more efficiently and for less cost than with conventional casing crews and equipment.
The Role of Risk Management in Development and Application of New Technology
Authors: Levett B. A. , Brandt H.
Published: December 2007

Exploration and development drilling continues to move toward deeper targets both in terms of water depth and reservoir depth. It is characterized by significant costs, technical challenges and high consequences of failure. Significant costs can easily turn a discovery into a marginal field, making it unattractive to pursue. Technology plays an important role in reducing drilling time and well cost. Application of technology (proven technology applied to new areas and new technology) has considerable potential, but also has high risk exposure. A risk management process becomes essential for successful drilling programs. Key components of risk management as it relates to drilling applications include identification and management of well control risks, economic risks associated with non-productive time, unplanned events and equipment reliability, and qualification of technology prior to application. In most situations, capital expenditure and operational expenditure are used to determine which path a project should take. A third component, expenditure associated with risk, is not often considered and yet can drastically alter the overall expenditure of a selection to the point of making it a bad choice. Case studies are presented in this paper of application of risk management to several different areas including active heave drawworks, dry tree completions and subsea completions. In all cases the application of risk management reduced risks in terms of both economics and safety. It is imperative to manage risk and uncertainty in the application and development of new technology in order to keep the new frontiers of drilling economically viable.
U-Tube Wells – Connecting Horizontal Wells End to End Case Study: Installation and Well Construction of the World's First U-Tube Well
Authors: Lee Dean , Hay Richard , Brandao Fernando
Published: December 2007

Although wellbores have been intersected before — both through planned intersections for the purpose of well control and through unplanned wellbore collisions — they have not been intersected for the purpose of actually joining their wellpaths to effectively create one smooth continuous conduit from one surface location to another. There is just one exception: the very large conduit between England and France! The purpose of this paper is to review the planning and execution of what is believed to be the world's first planned successful joining of two such horizontal wells, with a slotted liner to casing connection in between them.
Fatigue evaluation of Drilling Risers for Harsh Environments and Ultra Deepwater Developments to Allow Optimised Riser Life and Inspection Plans
Authors: Peter J. D. , Robinson R. , Metcalfe T. J. , Storesund W.
Published: December 2007

Recent experiences with current drilling risers in harsh and deepwater environments have identified shortcomings in the current design standards, which require a closer review for the future. With recent improvements in analytical methods and better field data, it is now possible to develop a much more accurate understanding of riser performance than ever before.

This improved insight into riser operating behaviour has highlighted that current demands in environmental and operating requirements are now taking the current riser designs to their limits and it is important to understand those limits to establish better margins on current operations and to improve design standards to meet these demands in future.

Particular areas of concern are:

Current Design Standards for Low Temperature Operations, in particular the dependence on API 16 Charpy V Notch Standards for riser toughness requirements. The requirements for fatigue assessment criteria in the design standards and how it should be applied, to enable effective inspection and maintenance programmes to be established. Assessment of different operating parameters, which are not normally considered in design standards, but are now having significant impact on the operability of the risers. How risers should be assessed for classification purposes taking into account the above concerns.

The paper examines recent experiences in harsh environment and deepwater riser operations, which has highlighted these concerns and the limitations it has put on the operations.

Finally the paper concludes on recommendations for improvements to the current industry standards to enable further discussion and to suggest areas for development in riser design, which may mitigate some of the current issues.
Experience Using the First Commercial Pad and Probe Style Formation Tester While Drilling Service Has Led To Value Creation at the Valhall Flank Development
Authors: Roberts Ifor , Kendall Martin , Proett Mark , Siess Charley , Hveding Frode , Solbakk Tommy
Published: December 2007

GeoTap®, a new formation testing while drilling (FTWD) service, was introduced to the Valhall Flank Drilling campaign in May 2003. Introduction of this service was anticipated to be the most cost effective solution for gathering pressure data on these long horizontal wells. After the first well, the equipment was modified; and the rate of success increased from 20% to 90 %. As of November 2004, the service has been run in seven wells. In this paper, we review the value the service has added to the drilling campaign and also review the experience gained with the service during its first year.

The drilling environment is dynamic with hydrostatic pressure constantly changing. The new tool offers the capability to perform pressure tests in this environment with the mud pumps on or off. As an essential part of FTWD job planning, estimates are made concerning the impact of hydrostatic pressure changes and supercharging prior to logging a well. In most cases, these estimates show that pressure data gathered with this service compare favorably to other pressure measurements, such as those gathered during perforating and stimulating.

The field examples presented demonstrate the field procedures used to gather pressure measurements and the added value from acquiring this data during the drill phase. Knowledge of the reservoir pressure distribution in these wells was crucial to understanding flow dynamics across the field and optimizing well decisions. These data have also impacted perforation and stimulation procedures that would not have been foreseen using conventional wireline tests. The data have been used to optimize the drilling process by providing key information for the TD decision.

Finally, conclusions are drawn regarding FTWD technology today and regarding its future direction for the Valhall Flank drilling campaign in particular.
Predicting the Formation Fracture Gradient of Middle East Reservoirs Using Non-Parametric Optimal Transformations
Authors: Nashawi I. S. , Malallah A.
Published: December 2007

Proper planning and execution of deep abnormal pressure wells, stimulation treatment and reservoir exploitation require, among other factors, good estimates of fracture gradient. It has been demonstrated in the literature that most of the available fracture gradient correlations do not yield dependable results when exposed to data away from the geographical region where they were initially developed.

This paper presents non-parametric optimal transformations that are accurately capable of estimating the fracture gradient. The transformations are completely data-driven and do not assume any a priori functional form. The model presents the fracture gradient as a function of pore pressure gradient, rock density, and depth. The data set used in the study consists of more than 21000 points taken from 16 wells drilled in seven different geologic prospects covering more than 200 square miles. The excellent results obtained from the proposed model establish a new simple tool for fracture gradient calculation that is based on readily accessible variables. The proposed model is demonstrated and validated using several examples from different fields in the Middle East. The computed results of the various cases are in excellent agreement with the measured values with an average absolute relative error of 6% and a standard deviation of 0.05 psi/ft.
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

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

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

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

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

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

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

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

A 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

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

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

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

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.