bluuebunny/crossref_metadata_2025 huggingface dataset:
Research into Material Selection for Down-hole Tubing by using Dynamic Field Tester
Authors: Takabe Hideki , Ueda Masakatsu , Yamamoto Eiji , Masatomo Hiroaki , Ihara Masarou , Saito Teiji , Morsi Kamal Mohamed , Khatem Obaid Saeed , Rabti Mohamed Faraj
Published: December 2007

Many oil and gas fields are being operated under severe conditions with the presence of corrosive gases such as Hydrogen Sulfide (H2S) and Carbon Dioxide (CO2). To mitigate the negative impact on operation, CRAs (Corrosion Resistant Alloys) are commonly used and getting more and more popularity. However, the selection of an appropriate CRA for a given corrosive environment requires much engineering effort, particularly for high temperature gas wells with high concentration of H2S and CO2.

In this research program, the corrosion resistance of many types of CRAs (13Cr, super 13Cr, Duplex stainless, Ni base alloy), carbon steel (L80) and low alloy (SM90SS) was evaluated in an actual gas well stream in UAE by using a Dynamic Field Tester (DFT). The DFT can permit an optimum selection of materials for tubing strings and flow-lines for use in corrosive environments. Also, concerning to these candidate materials, 4 point bent beam tests were carried out in the laboratory at elevated temperatures in 25% NaCl test solutions which were saturated with the produced gas that had been sampled from the well to evaluate the resistance of the materials to stress corrosion cracking (SCC) and general and localized corrosion.

Long-term DFT tests showed that the corrosion rate of carbon steel and low alloy steel was measured to be less than 3.1MPY and those of CRAs were less than 1MPY. Namely, all the tested materials showed lower corrosion rate than the popular criterions of an acceptable corrosion rate that are 4MPY for carbon and low alloy steel and 2MPY for CRAs. Long term laboratories tests in wet H2S environment showed that carbon steel and low alloy steel suffered from corrosion severely and corroded out partly. These tests also showed that only super 13Cr steel suffered from SCC and the other materials did not suffer SCC.

Our phase behavior study on the produced water and condensate suggested that even carbon and low alloy steels would hardly corrode when the metal surfaces were predominantly wetted with oil. However, those steels are considered to corrode severely when the metal surfaces are wetted with water in this particular UAE gas-condensate field. Therefore, there is a possibility that carbon steel is suitable material for the typical gas well in UAE, if an environment is not water wet. However, if an environment is water wet, SM2535 (25%Cr-35%Ni-3%Mo alloy) and higher grade materials are suitable material for the well.
Development of High Speed Inspection System for COS Tank Bottom Plate
Authors: Haga Hiroyuki , Ohta Masahide , Tarmoom Ihab O.
Published: December 2007

One of the major causes of leaks of storage tanks is thickness reduction of bottom plates due to unexpected corrosion of under surfaces of plates. And it is extremely difficult to detect such defects or analyze corrosive trend of the whole bottom plates by other inspection systems. On the other hand, it is asked for curtailment of maintenance expense. Such a background is taken into consideration. We were inquired about the method of grasping the status of the background of tank bottom plates quantitatively with high precision. We have succeeded in development of prototype inspection equipment and system. This development project was supported by Abu Dhabi National Oil Company (ADNOC) and New Energy and Industrial Technology Development Organization (NEDO) in Japan.

Developed inspection system (prototype) consisting of ultrasonic measuring unit having a 120mm of inspection width and data processing unit enables to identify such corroded condition accurately by continuous measurement of whole bottom plates of tanks. Especially, it was aimed at enabling measurement over GRP film (Maximum thickness of 6mm). This system will contribute to dedicated predictive maintenance to ensure safety operation of tanks.
Simulating Carbon Dioxide Sequestration/ECBM Production in Coal Seams: Effects of Coal Properties and Operational Parameters
Authors: Sams W. Neal , Bromhal Grant , Olufemi Olufemi , Sinisha Jikich , Ertekin Turgay , Smith Duane H.
Published: December 2007

Carbon dioxide sequestration is a promising technology for reducing anthropogenic greenhouse gas emissions while fossil fuels are still being used. The costs associated with CO2 sequestration are often high; however, in certain circumstances (e.g., enhanced oil recovery) these costs can be more than offset by the benefits of additional incremental hydrocarbon production. Primary production of coalbed methane is a well-developed technology, but secondary production, through the injection of CO2 or N2 has undergone relatively little study. Recent research suggests that carbon dioxide preferentially sorbs to coal, displacing methane, making CO2-enhanced coalbed methane production an ideal candidate for CO2 sequestration.

We use PSU-COALCOMP, a dual-porosity coalbed methane simulator, to model primary and secondary production of methane from coal, for a variety of coal properties and operational parameters. Our base well pattern consists of four horizontal production wells that form a square, with four smaller horizontal producers/injectors at the square's center. Primary production of methane and water is simulated until a specified reservoir pressure is reached, after which CO2 is injected in the center wells to displace methane, extending the reservoir's production of methane. Production continues until the CO2 concentration in the produced gas is too high. By modifying coal properties, such as permeability, porosity, degree of anisotropy, and sorption rates, we have approximated different types of coals. By varying operational parameters, such as injector length, injection well pressure, time to injection, and production well pressure, we can evaluate different production schemes to determine an optimum for each coal type.

Any optimization requires considering a tradeoff between total methane produced (or CO2 sequestered) and the rate of methane production. Values of aggregate methane production and methane production rate are presented for multiple coal types and different operational designs.
Development of Composite Progressing Cavity Pumps
Authors: Klein Steven T.
Published: December 2007

The newest technological advancement in the Progressing Cavity Pump (PCP) industry has been the development of composite stators and rotors. Included in this design concept is a reversing of the conventional elastomer and hard surface interface. The stator, in this design concept, is made of a hard composite material and is placed in a steel tube jacket. The rotor can be made of steel or composite material and coated with an even thickness of a soft and durable polyurethane. The urethane offers increased wear resistance and mechanical properties over conventional elastomers and the even thickness offers additional performance enhancements. Also, the elastomeric placed on the rotor offers the well-servicing advantages of the wear element being located on the end of the sucker rod string rather than on the end of the tubing string. The composite PCP becomes a low cost, highly durable PCP that incorporates the emerging even thickness elastomer technology.
Drill-String and Casing Design for Horizontal and Extended Reach Wells - Part I
Authors: Cunha J. C.
Published: December 2007

This paper will address some important factors that should be considered when designing drill-strings for horizontal and extended reach wells (ERW). A second paper will look into the issues of casing design for the same type of wells and present some practical field cases and examples of drill-string and casing design for ERW.

Buckling of the string and its influence on reach capability, fatigue and directional control will be emphasized.
Horizontal Water Disposal Well Performance in a High Porosity and Permeability Reservoir
Authors: Harding T. G. , Smith K. H. , Norris B.
Published: December 2007

Nexen Petroleum International Ltd. (Nexen) has a 52 percent interest and is operator of the Masila Block in the Republic of Yemen. Oil and water are produced mainly from the under pressured Qishn Formation, a non-marine to marine clastic sequence of Lower Cretaceous Age, which is roughly 200 feet thick and lies at a depth of 5500 feet from surface. Currently oil production is 230,000 BOPD at a water cut of about 80 percent. The one million barrels of water produced each day are currently reinjected under matrix injection pressures into 24 vertical and 4 horizontal wells. These are completed in the best quality sands (the S2/S3 members of the Upper Qishn Formation) that have average porosity and permeability of 20% and 3700 md, respectively.

Despite the exceptional disposal reservoir quality, injection problems continue to exist that have caused Nexen to study and evaluate numerous methods of improving injectivity. After extensive laboratory core and field testing, hypotheses have been developed to explain the behaviour of the water disposal wells including the so-called ‘check-valve effect’. Horizontal wells and proppant fractured wells were employed to test the hypotheses and to improve injectivity.

This paper reviews the laboratory results and discusses the placement of horizontal injectors along with the drilling and completion details of the wells. The performance of the horizontal disposal wells under matrix injection is compared to conventional vertical disposal wells and proppant fractured vertical wells. Produced water is expected to reach 1.5 MMBWPD and improvements in disposal well performance will reduce the number of wells that will need to be drilled to handle this volume, thereby improving overall project value.
Effect of Scale Dependent Data Correlations in an Integrated History Matching Loop Combining Production Data and 4D Seismic Data
Authors: Aanonsen S. I. , Aavatsmark I. , Barkve T. , Cominelli A. , Gonard R. , Gosselin O. , Kolasinski M. , Reme H.
Published: December 2007

The use of time-lapse data, or 4D seismic, in conjunction with production data in computer aided history matching of reservoir models requires that the various types of data are incorporated in a single objective function measuring the mismatch between the simulated and measured data. In the context of linear maximum likelihood estimation, the contribution of seismic data and production data to the objective function can be balanced on the basis of the sum of the inverse of the data and model error covariance matrices. Methods to estimate these covariance matrices for the combined set of production data and seismic impedance are presented. Generally, the seismic data will be correlated leading to a nondiagonal error covariance matrix. This matrix will also be very large, and efficient methods to invert this matrix are required. This is done using a very fast discrete convolution inverse based on multiplication of block Toeplitz matrices. It is shown that the regression may converge to a wrong solution if incorrect values for the data correlations are used.

The presented methodology is applied to an actual history-matching project using data from a North Sea oil field, and a procedure for mapping the time-lapse seismic data and covariance matrix from the seismic grid to the simulation grid is presented. The data seems to contain information about distribution of gas and oil not recovered by history matching to production data only. However, it turned out to be difficult to obtain a good match to the time-lapse seismic data in the regression. It is not clear whether this is due to large uncertainties in the data, incorrect petroelastic model, or incorrect parameterization. This should be investigated in future work.
A New Method for Calculating Well Indexes for Multiple Wellblocks with Arbitrary Rates in Numerical Reservoir Simulation
Authors: Peaceman Donald W.
Published: December 2007

In numerical reservoir simulation, the well index is used to relate the flowing well pressure to the numerical wellblock pressure. The well index is usually calculated from the equivalent wellblock radius. A previous paper presented an exact relationship for the equivalent wellblock radius for multiple wells with arbitrary rates.

In this paper, a new, simpler, and more general, equation is presented for calculating the well index for all nw wellblocks in a reservoir. Arbitrary wellblock flow rates and interactions between wellblocks are fully accounted for. The data required for the new equation may be obtained in a preprocessor by calculating nw single-phase pressure distributions. Then an accurate WI can be calculated for each wellblock at each timestep, even under conditions where well rates vary with time.
Compositional Streamline Simulation of Field Scale Condensate Vaporization by Gas Injection
Authors: Seto C. J. , Jessen K. , Orr F. M.
Published: December 2007

This paper presents an application of compositional streamline simulation in modeling enhanced condensate recovery via gas injection. These processes are inherently compositional and detailed compositional fluid descriptions must be use to represent the flow behavior accurately. Compositional streamline simulation results are compared to those of conventional finite-difference (FD) simulation for evaluation of gas injection schemes in condensate reservoirs.

We present and compare streamline and FD results for two-dimensional (2D) and three-dimensional (3D) examples, to show that the compositional streamline method is a way to obtain efficiently estimates of reasonable accuracy for condensate recovery by gas injection.
A New Formulation for the Implicit Compositional Simulation of Miscible Gas Injection Processes
Authors: Bowen Garf , Crumpton Paul
Published: December 2007

Compositional simulation is an important tool in gas injections studies. Often the aim of a gas injection project is to enhance the sweep efficiency by generating miscible displacement, either by utilizing a first contact or multiple-contact process. The compositional simulator is the only tool available to quantitatively study this behavior in a field setting.

The paper introduces the concept of treating a single-phase hydrocarbon as a separate distinct phase. This has the effect of reducing discretisation non-linearities in single-phase regions and allowing an implicit solution to converge efficiently. A number of small illustrative models will be used to demonstrate the technique, where the effect of varying degrees of implicitness will be reported, these being fully implicit, IMPES and AIM. In several of the example cases the standard implicit solutions are shown to fail entirely. The CPU advantage of the reduced non-linearity will be illustrated using a field scale example solved with an adaptive implicit method.
Streamline Methodology using An Efficient Operator Splitting for Accurate Modelling of Capillarity and Gravity Effects
Authors: Rodriguez Pedro González , Segurat Manuel Kindelan , Morenot Francisco J. Mustieles
Published: December 2007

The flow of hydrocarbons in a reservoir is a very complex process involving the interaction of several fluids and rock. Accurate and fast modelling of this complex flow is crucial to optimize reservoir exploitation.

We have developed a 3D streamline based reservoir simulator for two phase (water and oil) incompressible flow. In this case, the model simplifies to a non-linear elliptic equation for the pressure, coupled to an equation for the evolution of saturation. The streamline method assumes that displacement along any streamline follows a one-dimensional solution, and that there is no communication among streamlines, so that the 3D saturation equation is decomposed into a set of one-dimensional problems. It takes advantage of the fact that the pressure varies slowly compared to saturation and therefore needs to be updated after several steps in the saturation equation.

The decoupling of the pressure equation from the saturation equation speeds up the simulation orders of magnitude with respect to the conventional finite difference method, and this increase in speed is very important in modern reservoir engineering.

The method is best suited to problems dominated by displacement as opposed to gravity and capillarity. However, these effects can be taken into account in the model and we will show how to use operator splitting techniques to this end.

We will describe the main characteristics of the streamline method, analyze different numerical methods to solve the non-linear hyperbolic equation along streamlines, and present numerical results to show the effects of capillarity in the production of the reservoir.
Managing a Complex Deepwater Deposit through Advanced Simulation Technologies: Balder Field, Norway
Authors: Wang Gann-Shyong , Rossen Robert H. , Hjellbakk Andor , Sun Michael C.
Published: December 2007

The Balder Field is located in the Norwegian sector of the North Sea, about 190 kilometers west of Stavanger, Norway. The field consists of 8 separate hydrocarbon accumulations (mostly in mounded structures) in three separate stratigrahic units of Paleocene and Early Eocene age. The field has been on production since September 1999. During the production history, it has been observed that the interaction between the producing reservoirs, the Paleocene aquifer and the Eocene gas cap plays a significant role in controlling the overall field performance.

A full-field reservoir simulation model was developed for the Balder Field for reservoir management and surveillance. The model was built using a state-of-the-art reservoir simulator developed by ExxonMobil. Application of advanced features in this new simulator has significantly improved the accuracy of the model and the efficiency of modeling work. Key features highlighted in this study are: Gridding to faults and wells allowed more accurate representation of fluid movement without a significant increase in model sizeFlexibility of unstructured gridding allowed rapid generation of models with grid refinement over different reservoir regions to improve the efficiency of history matching efforts. This feature has the benefit of focusing history matching on a particular reservoir while still representing the correct interaction with other producing reservoirs in the field. A total of eight models of this type were built during the his tory matching phase of the study.Feedback between Geologic and Flow Models resulted in rapid cycle time (less than 1 day) for a revised geologic model to be carried through to complete simulation. Quick feedback between geologic and flow models improves interaction between geoscientists and reservoir engineers, hence the quality of history matching.Coupled wellbore/reservoir simulation resulted in an accurate representation of hydraulics in a subsea production system.
Control-Volume Distributed Sub-Cell Flux Schemes for Unstructured and Flow Based Grids
Authors: Edwards Michael G
Published: December 2007

New locally conservative flux continuous formulations are presented for general grids comprised of quadrilateral and or triangular grid cells. The schemes guarantee that a symmetric positive definite discretization matrix is obtained for both an arbitrary polygonal control-volume distributed formalism and a new sub-cell distributed formalism.
Monodiameter Drilling Liner – from Concept to Reality
Authors: Campo Don , Williams Charlie , Filippov Andrei , Cook Lance , Brisco David , Dean Bill , Ring Lev
Published: December 2007

Many in the oil and gas industry initially viewed the idea of a monodiameter well as a radical concept. But with the recent success of a field trial well, the monodiameter well has moved from concept to reality and is now a viable well construction process.

The monodiameter well is a breakthrough in the oil and gas industry. This technology allows multiple strings of the same size drilling liner to be installed in a well without a decrease in internal diameter (ID). The elimination of reducing ID is accomplished by an over-expansion of the monodiameter drilling liner and the base casing in the overlap section.

The monodiameter well construction process involves installing a monodiameter drilling liner below the casing and expanding it and the overlap. The resulting ID will allow additional monodiameter drilling liners to be installed and expanded without reducing the ID experienced in a standard telescoping casing program. Thus the expansion of the monodiameter liner creates a single ID.

The benefit of the monodiameter well construction process is that it reduces total drilling costs, especially in challenging areas, and enables operators to maintain the well's optimum completion diameter.

This paper briefly discusses the monodiameter drilling liner's transition from concept to reality, and focuses on the field installation of the monodiameter drilling liner. This paper also discusses the potential cost savings of using the monodiameter well construction process.
Completion of an Underbalanced Well Using Expandable Sand Screen for Sand Control
Authors: Cuthbertson Robert L. , Green Annabel , Dewar John A. G. , Truelove Brian D.
Published: December 2007

Recent technology advancements now make possible the deployment and expansion of Expandable Sand Screen (ESSTM) into an underbalanced well. This accomplishment opens up the door to bringing the well-established benefits of UBD into the area of less consolidated sandstone reservoirs that require some form of sand control. A likely target for these combined services is the deepwater offshore arena where undamaged high rate producers are required to meet critical and demanding economic criteria.

Key to achieving this desirable end result is the development of a new full-bore Downhole Deployment Valve (DDV) that serves as a subsurface lubricator valve for running the unexpanded ESSTM safely into the live UBD well. Additionally, new improvements in the compliant ESSTM and associated running and expansion tools result in the largest possible internal screen diameter post expansion. The elimination of gravel packs and conventional sand screens results in significant production improvements over alternative solutions. By adding the advantage of reduced filtrate invasion and solids plugging of the sand face through drilling and completing the well underbalanced, both of which impair the well's ability to achieve maximum productivity or full depletion of the potential reserves, an optimum solution is achieved. The result: maximum flow rates, effective sand control and capture of a higher quantity of reserves.
Expandable Drill Bit Provides New Method of Drilling Increased Diameter Hole
Authors: Brown Martin D. , Gledhill Andrew D.
Published: December 2007

It has long been recognised within the drilling industry that the ability to drill an increased diameter borehole, having passed through a restricted casing and/or tubing diameter, can provide significant advantages. Among these is the ability to incorporate novel well construction techniques, using both solid and/or expandable tubulars, as well as Drilling with Casing possibilities, in which the casing is run immediately behind the bit. The opportunity to successfully incorporate these new techniques can thus enhance well design to yield significant economic and well control gains.

Current techniques for drilling such increased diameter holes, such as bi-centered bits and under-reamers, have limitations on their ability to expand, whilst at the same time compromising the cutting structure presented to the formation. Additional limitations include limited reaming and back reaming capabilities, as well as non-uniform directional response. This can lead to well construction problems and reduced drilling performance. One embodiment of the technique of Drilling with Casing requires a bit which can be retrieved through the existing casing string. To achieve this and to maximise drilling performance requires a device with a formation cutting structure, indistinguishable from a standard PDC drill bit but capable of being withdrawn through a restriction significantly smaller than the borehole size just drilled. This concept leads to the possibility that a viable solution to the task of drilling increased diameter holes could be a bit that offers substantial expansion capabilities while still presenting full cutting structure to the formation.

In this paper the authors will discuss the earlier problems and solutions and then present a new approach with an "Expandable Drill Bit". They will discuss the design concept, development and prototype construction of such a bit and will also present details of the successful field trials and the minor design changes that resulted from them. They will conclude that use of an "Expandable Drill Bit" is a viable tool for a variety of drilling applications.
Abandonment of the Hutton TLP Wells
Authors: Plumb A. B. , Stewart A. , van de Laar J. , Milton P.
Published: December 2007

This paper reviews the wells abandonment aspects of the Hutton TLP decommissioning project, highlighting lessons learned during the project to achieve the early sailaway date in 2002.

The Hutton Field produced via a tension-leg production and drilling platform (TLP) located in the East Shetland Basin, producing from 32 oil producers and water injection wells.

The TLP was a floating structure with the wells utilising a subsea wellhead system tied back via rigid 9.5/8" production risers, terminating on the wellhead deck with a Tubing Head Spool (THS). The risers were supported by a tensioning system from the TLP. The lower completion tubing was supported at c.1000 ft MD BRT by use of a 9.5/8" subsea hanger or annular packer, with the final 1000 ft of 5.1/2" tubing being landed in the THS. The THS and hanger were topped with a "dry" 5000psi FMC Xmas Tree.

Due to the decreasing production and increasing water cuts of the Hutton wells from 2000 onwards, continued use of the TLP as a commercial proposition was under continuous review. Through late 2000 and early 2001, contingency plans were worked up for well abandonment and the poorer-performing wells on the field with no sidetrack options were identified for early abandonment. Full well abandonment commenced in July 2001 with a target date of mid-2002 for Hutton TLP sailaway.

In order to fast-track the well abandonments, a phased approach was employed, allowing concurrent operations, achieving a considerable time saving over a more conventional approach for such technically challenging wells. Given the number of wells and the repetitious nature of the work, a technical limit approach was also adopted to ensure that lessons learned from the work were quickly integrated and fed back into the ongoing project.
Drilling Contractor Safety Management System
Authors: Blank Bob , Prewitt Annette
Published: December 2007

A drilling contractor exists to provide the personnel, equipment and services that the market desires. In addition to these tangable assets, the successful drilling contractor also requires a reputation for safety and operational performance. All five of these assets must be effectively managed for a drilling contractor to survive.

This paper will cover the formal management system created and implemented by one offshore drilling contractor to manage safety. An overview of the Safety Management System (SMS) and its most important components are provided.

Development and evolution of the system into one holistic system that meets the safety, environmental and regulatory needs of the company's worldwide fleet is discussed.

Also covered will be the steps taken to ensure the workforce's knowledge of and participation in the system and the steps taken to monitor and continueously improve the system's effectiveness.
Real Time Monitoring of Hole Cleaning on a Deepwater Extend Well
Authors: Martins A. L. , Villas-Boas M. B. , Taira H. S. , Aragão A. F. , Amorim R. A. F. , Galeano Y. D. , Bove A. , Waldmann A. T. A.
Published: December 2007

This paper details the first utilization of a cuttings flow meter device on a floating platform. This device was installed at platform PETROBRAS – X during the drilling of an extended horizontal well (5211 m total depth) at 1212 m water depth. Since hydraulics and cuttings removal were major issues during drilling, the CFM concept proved to be an important tool to evaluate hole conditions. A discussion on the adequacy of hole cleaning operational procedures and on the uncertainty in results evaluation is also included.
Key Initiatives Improve Production Testing Performance, Deepwater West Africa
Authors: Schuberth Paul C. , Garcia Enrique M. , Walker Mike W. , Akers T. Jay
Published: December 2007

Since 1996, ExxonMobil has conducted an extensive deepwater exploration / appraisal program in West Africa. In an effort to achieve improvement in production testing performance, ExxonMobil's West Africa Deepwater Drill Team pursued key initiatives to deliver quality well test operational results. These initiatives included performing effective long-term and near-term planning, highgrading equipment quality control and inspection practices, making appropriate use of selective new technology, enhancing standardized procedures by capturing lessons learned and best practices, performing rig-site engineering supervision of production testing operations, and communicating captured follow-up recommendations to service contractors. To execute these continuous improvement initiatives, a single dedicated test engineer was assigned to plan and oversee all West Africa well testing operations. As a result of this increased focus, the average non-productive time (NPT) per test has been reduced from approximately 30% to 6% and the overall test time has been reduced by about 40%. The methods and resources used to achieve these improvements are discussed in detail in this paper.
A New Approach for Running Production Casing from Semi-Submersible Rigs on Highly Deviated Wells
Authors: Rae G , Williams H , Hamilton J
Published: December 2007

This paper outlines a new technique for running production casing from semi-submersible drilling rigs on highly deviated wells and was used for the first time on the Captain Field, UKCS, operated by ChevronTexaco. The technique, which incorporates selective-flotation techniques, has been used successfully on three subsea wells to date. This is believed to be the first employment of the above technique on semi-submersible rigs.
Drilling HP/HT Wells in Bosque Field, Venezuela - The Aloctono Block Challenge
Authors: Avila J. C. , Zerpa E. , Rojas L. , Salas J. G.
Published: December 2007

Bosque field presents some of the most challenging conditions for drilling, in Venezuela. The sandstone reservoir can be found below 20,000 ft, pressures exceed 12,000 psia, and temperatures are over 300°F. The main characteristic of this area is a great inverse fault in the north-south direction called Pirital's landslide. Because of this landslide, Cretaceous formations overlie a Miocene formation. These have been called the Aloctono block. So the geology is very complex, containing faulted structures, large dips, and hard and abrasive rocks. Drilling operations struggle to overcome numerous problems, such as low rates of penetration (ROP), wellbore instability, lost circulation, and trajectory deviation.

Since the discovery in 1988, these obstacles have seriously affected the field's profitability. To optimize the reservoir management strategies, the operator Petroleos de Venezuela S.A. (PDVSA) commissioned a delineation and development project. A fundamental issue has been to improve drilling performance because of its notable influence on field development. To achieve this goal, a multidisciplinary drilling team was formed, involving not only drilling experts but also personnel from other areas, such as production and reservoir engineers, geophysicists, geologists, and petrophysicists.

To construct the first project's well, the team selected the well location by seismic 3D data, combining the reservoir objectives and the best conditions for drilling, determined the bottomhole assembly (BHA) with best vertical response by drillstring simulation, and used near-balance drilling and 6⅝-in drillpipe to increase the ROP. These practices led to reaching a total depth of 21,199 ft, an ROP increase of 25% in the Aloctono block, and the largest Aloctono thickness drilled, 12,850 ft, to reduce the drilling time and the well-construction investment. A key factor was the 9⅝-in casing run, which required a new design and a detailed analysis of the rig and tools capabilities because of being the heaviest casing ever run in Venezuela (maximum tension of 1.25×106 lb).
Brae Field Extended Reach Drilling - A Case History
Authors: Lumsden George C. , Parker Jeff R.
Published: December 2007

This paper describes the experiences from drilling an extended reach well in February 2002 from a North Sea production platform constructed to develop a gas condensate reservoir, into an adjacent mature black oil field that had been previously developed with subsea facilities. The background to the project meant that a new conventional subsea type well tied into the existing infrastructure would not be able to deliver some of the key elements in developing reserves from the field.

Conceptual drilling engineering studies indicated that an extended reach well would be viable with a relatively minimal upgrade to the existing platform drilling facilities. The experiences of numerous other ERD (extended reach drilling) projects are well documented and whereas most issues are described as "good drilling practices" and are aligned company best practices, other issues were new to the organisation and required thorough review before deciding whether utilise that experience. Given this was the first such type of well for the company many of these issues were encountered.

HES (Health, Environmental and Safety) issues were particularly relevant to this project given the magnitude of the well, the human challenges with using unfamiliar equipment, and the environmental regulations governing the handling of drill cuttings.

Ultimately the project was sanctioned and after the numerous problems that were encountered, including three sidetracks and two lost BHA (bottom hole assemblies), the well successfully achieved it objectives attaining a final well TD (total depth) of 25,852 ft (7,880 m), a TVD (true vertical depth) of 13,810 ft (4,209 m) and a lateral displacement of 20,150 ft (6142 m). This paper presents the interpreted critical design considerations, details of the operational successes and failures, a summary of the lessons learned and the resulting developed best practice.
Improving Drilling and Completion Performance in the Norwegian North Sea
Authors: Garig Howard A. , Williams Bruce E.
Published: December 2007

Six subsea wells were drilled and completed by Esso Norge AS (ENAS) as part of the Ringhorne development in the Norwegian sector of the North Sea from 15 November 2000 to 2 December 2001. The program was completed in 125 meters of water using a semi-submersible drilling rig. Average well depth was +/− 3500 meters MD and had a vertical section of +/− 2300 meters. The wells were completed as natural sand packs using sand control screens in the horizontal sections. The entire program lasted 383 days and incurred a total of 52.5 days (13.7%) NPT-excluding weather. WOW accounted for 24.8 days (6.5%) NPT. These NPT figures are better than performance achieved by ENAS on the earlier Balder subsea development and below the average time in the industry for similar work.

Three key issues drove the performance on the Ringhorne Project; they were team structure, modification of the rig to program requirements and use of new technology. The Ringhorne drill team was drawn from the original Balder drill team so they were familiar with subsea drilling and completion operations. By applying best practices learned at Balder and incorporating them into the well programs the learning curve on this program was reduced significantly. The rig had most recently been used in a subsea P&A program, so the contractor was also familiar with the issues surrounding a subsea development program. The rig was upgraded with several drilling and completion related items, to optimize it for the upcoming drilling program and running of subsea completions. Some of these modifications were extensive in scope and implementation, such as a subsea equipment skidding system and underhull guidance package. They proved crucial to reducing NPT as well as extending the rig's operating window in harsh weather. The use of new also played a major role in the effectiveness of the project. This included use of a Rotary Closed Loop Steerable drilling system (RCLS) which greatly increased directional drilling performance and delivered a smoother wellbore which allowed for easier completion installation; in spite of longer completion intervals than on the previous program. Wireline intervention on completion installation was reduced by use of pump-open plugs and the use of a low solids oil based mud that eliminated the need for coiled tubing cleanout operations.

This paper reviews the engineering and operations processes used by ENAS to successfully complete this project. Opportunities to apply the learnings on future projects are highlighted.
A New Downhole Tool for ECD Reduction
Authors: Bern P. A. , Hosie Dave , Bansal R. K. , Stewart Donald , Lee Bradley
Published: December 2007

Wellbore pressure management is a critical part of the drilling process. In normal drilling practices, static and dynamic fluid pressures are used to contain formation pressures and to assure wellbore stability. Excessive fluid pressure while circulating can create problems including reduced operating margins between fracture and pore pressures and, in the extreme, lost circulation. To address these problems, an Equivalent Circulation Density (ECD) Reduction Tool (RT) has been developed.

The ECD RT is designed to counter the frictional pressure effects that exist while circulating. The tool is expected to have a broad range of drilling applications including; the narrow pore/fracture pressure margin deepwater environment, wellbores prone to instability, pressure depleted reservoirs, and extended reach wells.

The tool has the potential to: Improve wellbore stabilityExtend hole intervals and reduce casing requirementsImprove well controlReduce lost circulationReduce differential stickingImprove hole cleaning in ERD wells through the use of higher flow rates

This paper describes a new downhole tool for ECD reduction, which is run as an integral part of the drill string. A prototype tool has been built to operate inside 10c3/4″ to 13−3/8″ casing. This tool has undergone laboratory testing and full-scale technology trials are in progress. The design features of this prototype are discussed along with the laboratory test results obtained to date.
Dual Drawworks Provide Operational Redundancy and Reduce Cut and Slip Costs
Authors: Kyllingstad Åge
Published: December 2007

Dual drawworks is a new concept based on the AC gear-driven Active Heave Drawworks. If one of the two independent units fails, the other can still run the block and provide redundancy. Dual drawworks also improves rig efficiency due to higher capacities and savings of cut and slip operations.
Design Considerations and Field Performance of an Advanced Automatic Driller
Authors: Boyadjieff George , Murray Dave , Orr Alan , Porche Mike , Thompson Peter
Published: December 2007

Automatic Drillers have been used for decades. Most of these systems did a poor job of controlling weight on bit, which resulted in equally poor performance. Thus prompting two questions: "What is required to achieve a much better level of control of drilling parameters like weight on bit?" and "What field performance results do we see from improved control?" This paper will address these questions by examining the development and field performance of an advanced automatic drilling system. It will show how the entire system, not just the mechanics or the software, needs to be designed from a control system point of view. It will present the results of field usage of the system, and demonstrating the performance benefits resulting from improved control. Finally, it will suggest future developments for this type of advanced product.
Step Change In Time Efficiency Using An Innovative Leap-Frog Rig System In Yemen
Authors: Diggins E. , Frail O. , Sawa M.
Published: December 2007

Yemen Masila Block 14 has been actively explored and developed since 1987 by Operator Canadian Nexen Petroleum Yemen (formerly Canadian Occidental Petroleum Yemen), and partners Occidental Petroleum and Consolidated Contractors (Oil & Gas) Company. Previous drilling optimisation initiatives have reduced typical well drilling times at Masila from over 30 days on early wells to 14 days in 1999. Presently, a leap-frog drilling rig system is being used to reduce drilling operations time on development oil producer and water injection wells even further. Comprising of two complete drilling rig units plus a partial drilling rig system, it is an excellent example of cooperation between Operator and Contractor to achieve a win-win situation. The initial and primary reason for use of this drilling rig system was to reduce the rig out/move/rig up time spent between wells by the drilling rig packages. A more recent, although equally as important initiative, has seen the leap-frog rig utilized to drill the well surface holes, run and cement surface casing strings, nipple up and pressure test blowout preventers, and run the next hole section drilling BHA in the well ready for drill out. On average, use of this drilling rig system has saved 2.5 rig days per well compared to the utilization of conventional drilling rig systems at Masila. During an annual 75 well development drilling program with a 60% leap-frog drilling rig system utilization, approximately 112 rig days can be saved. This enables an additional eight wells to be drilled each year, assuming a 14 day well spud to spud drilling time (realistic for 6500 foot development wells at Masila).
Development and Performance Testing of the Hex Mud Pump
Authors: Kverneland Hege , Kyllingstad Åge , Moe Magne
Published: December 2007

This paper focuses on the development process of the Hex pump. Computer assisted analysis has been used extensively to optimize the pump structure and vital parts with respect to weight, strength and life. Interactive computer programs for replacing paper based documentation and service manuals have also been developed.
Performing eleven subsea interventions in fifteen days
Authors: Olsen Terje , Mjøs Harald Kvammen , Nergaard Arnfinn
Published: December 2007

Between 27th August and 12th September, 2001, Norsk Hydro performed eleven subsea well interventions in fifteen days in the Troll Oil field, West Norway.

The work was done from Smedvig's 5th generation, DP, dual derrick semisubmersible West Venture.

The selection of the strategy of using a high-spec, fullblown drilling and completion vessel was initially based on a budget of nineteen days for a total of eight interventions. It was later decided to include three more wells in the campaign. Performing eleven interventions in fifteen days implied an average of 43 % time saving relative to the budget.

This paper describes the scope that was covered, and the way the overall campaign took maximum advantage of the DP and the dual activity features of the West Venture.

The paper also presents a simplified comparison between the West Venture and the competing concepts: an anchored single rig semisubmersible, a DP single rig semisubmersible and a subsea wireline monohull vessel.

The comparison proves that the West Venture will normally outperform all known existing competing concepts through a very significant reduction of the overall time for the operations. A direct comparison with an anchored, single derrick rig yields a 70 % time saving thanks to DP and dual activities.
Lost Circulation Assessment and Planning Program: Evolving Strategy to Control Severe Losses in Deepwater Projects
Authors: Sanders W. Wayne , Williamson Roger N. , Ivan Catalin D. , Powell Donald
Published: December 2007

There was a time when simply dumping some mica or nut hulls down a wellbore was a standard procedure for stopping mud losses. Certainly, these materials still work – for some applications. But, many of today's drilling operations bear little resemblance to that not-so-distant past. The industry is accelerating its activities in deepwater and depleted zones, both of which present narrow operating limits, young sedimentary formations, and high degree of depletion overbalanced drilling. All of these now-common conditions are ideal for fracturing and lost circulation.

Drilling through and below salt formations presents a host of technical challenges as well. The thief zone at the base of the salt can introduce severe lost circulation and well control problems, often resulting in loss of the interval or the entire well. Controlling losses in this zone has proven to be extremely difficult. Very few lost circulation remedies have been successful, especially when using invert emulsion drilling fluids. The lost time treating severe sub-salt losses can last for several weeks, with obvious cost implications, especially for deepwater drilling operations.

This paper reviews the methods applied to avoid lost circulation in the sub-salt thief zone, as well as in the subsequent intervals for a Gulf of Mexico deepwater project and discusses the time and cost savings obtained. For maximum success in these situations, emphasis has been placed on assessment and planning rather than individual lost circulation products.

The authors will detail the Lost Circulation Assessment and Planning process that has been employed to explore and evaluate specific lost circulation problems and link them to existing products, systems and services. The integrative pre-planning process analyzes offset histories and formation data not only to identify risk zones but also to gather information on the exact fracture and pore size as well as fracture density. Afterward, detailed interval-specific decision-tree charts are developed for stopping losses encountered while drilling or tripping in.

In addition to discussing the application of this Assessment and Planning process, the authors will outline the lessons learned on the deepwater project, featuring pre-planning issues geared toward ensuring circulation is maintained throughout the wellbore.
A Multilateral Application in a Limited Hoisting Capacity Environment
Authors: Brister Ray , Bonner Julie , Broderick Mike
Published: December 2007

Technology suppliers have produced special systems to handle a wide range of typical multilateral applications. One of the less typical applications is an environment where rig capacity, specifically hoisting capacity, is a limiting factor. There is currently no prefabricated multilateral junction that does not require the ability to reciprocate and rotate the pipe to ensure proper downhole orientation. Even if the junction orients perfectly on the first attempt, confirmation by picking up and resetting is recommended with some systems. The hoisting capacity limitation in this case made reciprocation and rotation impossible in conventional well procedures. The only recourse was to focus on reducing hookload and friction in order to install the multilateral junction, which, in this case, proved very challenging. All available methods were employed, equipment was modified, and careful calculation was made to mitigate any possible equipment failure.

There are various ways to address hoisting capacity problems. Among them are weight reductions, lubricants, and torque reduction additives. In this case history, each of these primary methods was employed to install a hook-type TAML Level 3 multilateral junction (Chambers1 and Hogg2) resulting in a first for the operator, the service company, and for Level 3 systems in general.