bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimizing the Well Construction Process: Full-Waveform Data From While-Drilling Seismic Measurements in the South Caspian Sea
Authors: Haldorsen Jakob B. U. , Esmersoy Cengiz , Hawthorn Andrew , Krasovec Mary L. , Raikes Sue , Harrold Toby , Day David N. , Clippard James D.
Published: December 2007

Recent advances in logging while drilling have enabled the development of a seismic tool that acquires and transmits seismic data in real time during the drilling process. Examples of this technology demonstrate the use of this service to significantly reduce risk and uncertainty, enabling better decision making during well construction operations. Operationally, the service runs with no interference with normal rig operations.

This technology can have a significant impact on the cost of exploration and development drilling, particularly in the deepwater environment and other areas with significant seismic uncertainties.

The service was first used to drill a wildcat well in the South Caspian Sea. The well was deviated to intersect the reservoir section within a steeply dipping structure at about 4500 m true vertical depth (TVD) while avoiding faulting, high pore pressures, and areas of poor seismic data quality in the overburden at the crest of the structure. The key product of the new seismic tool, real-time check-shot data, was used to position the drill bit and the borehole on the seismic section used to plan the well.

Furthermore, an analysis of the seismic waveforms recorded in the tool memory demonstrates the capability of this technology to produce data of sufficient quality to allow imaging of the formation ahead and to the side of the bit. Images from the tool have higher resolution and good ties with the migrated surface seismic images.

Future advances in technology offer the exciting possibility of imaging significant distances ahead of the bit in relevant real time.
Application of Real-Time Resistivity and Annular Pressure Data in Reducing Lost-Circulation Events
Authors: Akamine Andres Y. , Bratton Tom , Onyia Ernest , Romanchock Mark
Published: December 2007

Lost circulation is one of the major risks associated with drilling in a deepwater or subsalt environment. The downtime spent regaining circulation and the associated well control issues increase the already high operating costs and introduce critical safety concerns. This paper illustrates how formation resistivity and annular pressure measurements, combined with time-lapse logging data, can be used to determine a more accurate fracture pressure, enabling cost-effective real-time drilling decisions.

Two examples are presented to demonstrate that an analysis of the resistivity and pressure data, viewed in both time and depth domains, contributes to a better understanding of fracture behavior. Lost-circulation problems occurring in weak formations far below the casing shoe can be located with logging data. Additional information enables relevant-time drilling decisions such as selecting proper mud weight, spotting fluids, and optimizing cementing programs.

The first example shows how abnormal real-time resistivity readings, suggesting the initiation of fractures, were confirmed with time-lapse measurements made while tripping out of the hole. The real-time resistivity data showed elevated resistivities suggesting fracture growth. This interpretation was confirmed with time-lapse measurements. The analysis provided the location of the problem zone, the formation type, and the wellbore pressure activating the fractures. In the second example, a minor water kick prompted the acquisition of a real-time openhole leakoff test followed by real-time resistivity logging. The additional information provided a better understanding of the initiated fracture characteristics and enabled drilling the section to total depth without mud losses.
A New Look for an Old Field – Multilateral, Underbalanced, Semi-Short Radius Drilling Case Study: Installation of a Seven Leg Multilateral Well
Authors: Lee Dean , Brandao Fernando , Sotomayor Gabriel , Lucena Humberto , Filho Paulo Silva
Published: December 2007

The purpose of this paper is to review the planning, execution and results of a Seven Leg, Semi-short Radius Multilateral Well drilled underbalanced in a very mature field in Northeast Brazil. It will explain such details as … why multilateral?? … why semi-short radius?? … why underbalanced?? … in an effort to explain the many thought processes and considerations when designing and planning drilling operations in depleted reservoirs.
Accessing Deep Reservoirs by Drilling Severely Depleted Formations
Authors: van Oort E. , Gradishar J. , Ugueto G. , Cowan K. M. , Barton K. K. , Dudley J. W.
Published: December 2007

In many maturing prospect around the world, operators are facing the challenge of having to drill through highly pressure-depleted formations in order to access lower-lying hydrocarbon-bearing zones. New technologies such as expandable casing are now becoming available to allow for extensions to conventional well designs in order to deal with depletion. However, before one can case off depleted formations, one first has to successfully drill them.

This paper highlights key aspects in the planning and execution of the Ursa A-11 well, which was drilled through a 5500 psi depleted sand to a deeper horizon. Drilling complications included risks of excessive mud loss, internal blowout and differential sticking on the depleted sand. Moreover, fracturing of the depleted sand carried the risk of jeopardizing production at a nearby horizontal well. Key factors in the successful drilling of the Ursa A-11 well included special drilling fluid design, rock mechanics study, pro-active use of borehole strengthening technology, integration of supplier and operator expertise, and excellent communication between all parties involved.
Thermal and Mechanical Considerations for Design of Insulated Tubing
Authors: Pattillo P. D. , Bellarby J. E. , Ross G. R. , Gosch S. W. , McLaren G. D.
Published: December 2007

Of the several options for controlling temperature in a well, vacuum insulated tubing (VIT) has proven useful in a number of applications. Use of VIT, however, necessitates unique design considerations, from both a thermal and mechanical perspective.

This paper describes the application of VIT for a particular purpose – to minimize temperature change, and associated annular fluid expansion pressures, in a deep water well design. The specific application, however, lends background to more general design considerations associated with VIT. Thermally, the importance of heat loss at the couplings to the overall design is discussed, using both numerical analysis and experimental results previously reported in the redesign of wells for the Marlin TLP. Mechanically, a detailed examination of the loads to which VIT may be subjected also uncovers special considerations.
Control of Contained-Annulus Fluid Pressure Buildup
Authors: Williamson Roger , Sanders Wayne , Jakabosky Troy , Serio Michael , Griffith James E.
Published: December 2007

Fluid trapped in the annulus of subsea wells can cause casing strings to fail. This condition occurs when casing annuli attain a closed-volume circumstance (when a well is cased, cemented, and head seals are set). During production, the heat transfer of the produced fluids to the casing strings causes the trapped fluid to increase in pressure. This condition is magnified in deepwater because annular fluids are cooler due to the cold deepwater environment. Laboratory testing indicates that thermal expansion of these fluids can cause trapped water- or oil-based fluids to increase in pressure above casing-collapse pressure, resulting in annular pressure buildup (APB).

This paper outlines a simple laboratory procedure and resulting data to determine the resulting trapped-volume pressure. Data from eight fluid combinations are presented. The temperature change during testing is an increase from 80°F to 230°F. The testing relates to the conditions commonly found in deepwater Gulf of Mexico.

The laboratory data obtained from this testing was used to design a spacer system for Walker Ridge 285 #1, a deepwater, subsea well located in the Gulf of Mexico. This paper also presents the job design and related procedure for the executed spacer system.
Casing-Conveyed Perforating System Presents a Unique Set of Drilling and Cementing Challenges: A Case History Study – Kenai Gas Field, Alaska
Authors: Garner J. Jay , Eller J. Gary , Tank Willard J.
Published: December 2007

Three wells have been successfully drilled, cemented and fracture stimulated in the Kenai Gas Field utilizing an industry unique Casing-Conveyed Perforating System (CCPS). This revolutionary system consists of perforating guns external to the casing and integral valves in the casing for zonal isolation while fracturing. During completion operations all downhole equipment is remotely actuated without wellbore intervention. In addition, downhole sensors were run on all three wells providing monitoring of bottom-hole pressures and temperatures during cement operations, as the cement cures, during stimulation operations, and ultimately over the productive life of the well.

Special characteristics of the CCPS, such as the need for precise depth control and irregular geometry, present a unique set of drilling and cementing challenges compared to conventional casing strings. For the case history wells reviewed in this paper a total of 43 perforating modules have been deployed with 15, 12 and 16 modules run in the KBU 42–7, KBU 24–6 and KBU 44–6 wells respectfully. Meticulous pre-planning by a multi-disciplinary team of professionals provided solutions to the many challenges encountered. This paper provides detailed descriptions of the three CCPS wells drilled to date in the Kenai Gas Field, including the drilling, running and cementing requirements and the solutions developed and utilized in field operations. Each of the three CCPS wells completed to date has been deemed engineering, operational and economic successes.
Smart Drilling with ELECTRIC DRILLSTRING™
Authors: Lurie Paul , Head Philip , Smith Jackie E.
Published: December 2007

This paper will present the results to date of a project to develop an electric drillstring, together with some ideas and visions of how this technology could make a step-change in well construction. The electric drillstring should enable electric power to be transmitted through the drill pipe, while simultaneously multiplexing data back to surface from the downhole drilling system. This could allow a range of improvements to the drilling process, that we shall call "smart drilling", which should result in reduced drilling costs and optimized well placement for maximum productivity.

The project has followed the normal phases in any technology development, but only the initial two phases of feasibility and benefit assessment have been completed. The initial phase was to learn what had been done in the past to transmit electrical power and telemetry in a drillstring, identify the key problems and try to come up with some novel solutions incorporating technical improvements from both within and outside the drilling industry. The key benefits of the new system were identified, together with a range of potential applications that could be available in both the short and longer term.

The heart of the system is a reliable electrical connector integral with a premium drill pipe thread that will behave like a normal tool joint during operation. This is combined with mid-body conductors, in this case sandwiched between a metal inner layer and the drill pipe body. The development of the first two prototypes, which are on the route map to the initial field test, will be discussed.

Smart drilling via an electric drillstring can offer a wide range of possible advantages over conventional drilling operations, which could include: Reduced drilling costs from the optimization of the drilling process by control of weight on bit using downhole traction or thrusters, and maintaining bit speed independent of flow rate.Reduced wellbore stability problems due to both reduced ECD via reverse circulation and knowledge of the pressure conditions from sensors distributed over the length of the well.Reduced costs by replacing wireline logging with realtime LWD systems.Reduced stuck-pipe in ERD-type wells from traction tools distributed along the drillstring.Improved well productivity from improved geosteering via immediate data feedback from the high quality telemetry path.The development of Seismic-while-drilling (SWD) utilizing downhole sources and recievers.The possible development of new sensors that take advantage of the excess power available downhole.

These concepts will be briefly discussed in the paper together with the results of an initial benefit assessment.
Bringing Efficiency to the Offshore Rig Contracting Business
Authors: Carter Steven M. , Ghiselin Richard G.
Published: December 2007

The worldwide offshore rig chartering business is a significant business with $7 billion to $10 billion in annual expenditures. A study of bidding and contracting practices reveals major inefficiencies in the processes involved in this business, and in the variability of economic decisions, as evidenced by fixture ranges of up to ± $55,000/day for rigs of similar capabilities.

The market lacks transparency. Rig chartering supply and demand have very different characteristics. While supply is essentially inelastic, demand is highly volatile. This creates complementary needs for operators and contractors.

Operators need: ■Knowledge of rig capabilities including recent contracts and activities.■Knowledge of rig availability and future commitments.■The ability to quickly develop multiple contingency drilling scenarios.■Easy collaboration with partners and colleagues.

Contractors need: ■Knowledge of upcoming drilling projects and rig capability requirements.■Knowledge of competitors' rig dispositions and capabilities.■Ability to manage their fleets.

Both need: ■Detailed current supply and demand and dayrate information in each market segment to facilitate tactical and strategic decision-making.■Standardized contracting processes.

Several companies are managing their rig contracting businesses online, using a real-time expert system to give them the insight they need.

Having the right rig for the right job creates tremendous economic advantages. Operators are able to use their drilling budgets more efficiently. Contractors are better able to match their fleets' capabilities with market conditions. This paper offers several examples of decisions that have benefited greatly from market transparency. For example, market insights were essential in helping to determine whether to invest in a rig upgrade or newbuild, as well as how much to invest. Similarly, the ability to lease rigs competitively on the spot market depends on access to market and competitive information.

This paper provides examples of efficiency improvements by both operators and contractors, as well as the methodology and results of price/risk analyses.
World Class Drilling in the Gulf of Thailand: North Pailin Project
Authors: Yodinlom Wiwat , Luckanakul Nat , Tanamaitreejitt Pichai
Published: December 2007

The North Pailin field, located in the Gulf of Thailand (GOT) had been evaluated during 1996–1997 with 15 delineation wells. Risked gas resources of 1,280 BCF (1 January 2002) will be fully developed with a Central Processing Platform (CPP) and a total of 357 development wells on 31 wellhead platforms (WP). However, thanks to a flexible performance-oriented operational philosophy, Unocal Thailand put North Pailin development on a fast track, aggressive timeline that moved the start-up project from well plan to cash flow within 9 months.

Each well of the initial first four-platform drilling program was highly deviated and followed a 3-D design in three sections: 11–3/4", 8–1/2" and 6–1/8". During this drilling campaign, many world class drilling records were achieved: In February 2002, North Pailin A-05 3D-well was directionally drilled from spud (325-ft mud line) to 11,388 feet TD in 1.9 days at $49.6 per foot.The 12-well program on North Pailin-A was completed within 34.42 days, 115,103 feet were drilled by average 4,387 SFPD at $64 per foot.For the entire four-platform, four rigs had drilled 618,786 feet (117 miles) out of 55 wells in the first quarter of 2002, at an average cost of $850K per well or $76 per foot.Together with those records, 307,140 man-hours were also achieved safely without any lost time incidents.

The records achieved on the North Pailin make it the most efficiently drilled development program so far in the GOT. A brief background of the North Pailin will be presented. However, the main focus is to highlight the key performance statistics and offers insights into the success of the North Pailin drilling campaigns.
Drilling 3D wells in Western Siberia
Authors: Matevosov Andrei , Iskander Diyashef , Dupuis Dominique , Baradat Yves
Published: December 2007

In order to improve the development of a field in Western Siberia, Sibneft elects to drill 3D wells (5000 MD) with long horizontal drain (more than 1200m). Due to geographical conditions prevailing in Siberia those wells are drilled from a cluster. In order to drill those wells a heavy land drilling rig (3000hp) from Pride Forasol, well services from Halliburton, Schlumberger and Baker groups were mobilized.
How Probabilistic Methods Were Used to Generate Accurate Campaign Costs for Enterprise's Bijupirá & Salema Development
Authors: Zoller S. L. , Graulier J. -R. , Paterson A. W.
Published: December 2007

Well construction costs were critical to the overall commerciality of Enterprise Oil's Bijupirá & Salema development. Enterprise's well engineering team opted for a probabilistic approach to cost estimating so as to account for the inherent risks in the well construction process.

Peak's P1® process was used to generate probabilistic time and cost estimates for each of the operational phases, however a new system was required to generate a probabilistic time and cost estimate for the whole development campaign. Summing the individual phase estimates would not provide a statistically valid overall estimate and learning curve and correlation effects also had to be accounted for. Peak developed the C1 system to use the probability curves output by P1® to generate a probabilistic time and cost estimate for the whole development campaign. The C1 system provided the necessary quality of data for Enterprise to make decisions on project viability.
Use of Pressure Gauges in Liner Running Strings during Liner Cementing Operations
Authors: Brehme J. , Bain A. D. , Valencia A.
Published: December 2007

With surface measurements alone, liner cementing operations are difficult to interpret because of the dampening effects of the mud and greater overlaying pressure events such as cement free fall. In April 2001, an operator in the North Sea started to use downhole memory pressure gauges in the liner running string to gather pressure data for evaluation of liner equipment performance and cement placement. The collected data has shown downhole pressure effects that have not been seen with surface pressure measurements. This data also allows comparison of actual and simulated downhole pressure, which can improve cement job simulations.
Advances in Tieback Cementing
Authors: MacEachern Douglas P. , Algu Dave R. , Cowan Mike , Harris Kirk , Snell Eric
Published: December 2007

New cementing technologies and techniques have been applied to the challenging task of cementing tiebacks for long-term integrity. Cement sheath stress analysis, reverse cementing, ductile cements, and delayed-gel slurries are among the technical advances in tieback cementing that have been applied in the Gulf of Mexico. This paper outlines the reasons and methods for cementing tiebacks, and details the most recent technologies.
Selection of Foamed Cement for HPHT Gas Well Proves Effective for Zonal Isolation—Case History
Authors: Pine Michael , Hunter Liz , Mutch John , Adam John , Griffith James E.
Published: December 2007

This paper describes the reasons for and execution of a foamed-cement job to provide zonal isolation for a high-pressure, high-temperature (HPHT) sidetrack wellbore. Because adjacent wells cemented with non-nitrified, HPHT slurry designs showed marginal success in achieving zonal isolation, foamed cement was selected as the most effective means to achieve the following objectives in the case history well: Prevention of cement-sheath crackingPrevention of annular gas pressure over the life of the wellHigh mud displacementNo free-water or gas channel developmentLow slurry fluid loss

The benefits of foamed cement compared to non-nitrified cement as they relate to these objectives are explained in the body of the paper. Comparison of the new well to the existing, conventionally cemented wells indicates that foamed cement can be a more effective means of providing zonal isolation than non-nitrified, HPHT-designed cements.

The following sections outline the grounds for choosing foamed cement and the steps taken to execute the foamed-cementing operation. Included are recommended practices for prejob analysis and planning, job execution, and post-job evaluation.
Real-Time Cement Expansion/Shrinkage Testing Under Downhole Conditions for Enhanced Annular Isolation
Authors: Goboncan Virgilio C. , Dillenbeck Robert L.
Published: December 2007

Ongoing problems with sustained annular gas pressure on producing wells wordwide is a prime indicator that more work is needed in understanding how cement system design can impact long-term annular isolation. One important area is the relative expansion or shrinkage of cement systems as they hydrate in the annulus of a well.

Most Portland cement systems undergo chemical and bulk shrinkage as they set. A number of chemical materials have been developed that can be added to cementing systems to overcome this shrinkage, and in some cases, even impart a degree of expansion. However, the process whereby the degree of shrinkage or expansion is measured has almost universally been some type of a single point test, performed at ambient conditions. This is typically the case even if the cement sample was first hydrated under downhole conditions.

The authors detail new methodology and test equipment that allows for the tracking of cement shrinkage and/or expansion real-time, under downhole conditions of pressure and temperature. The system allows for the application of curing pressures in either an aqueous or non-aqueous environment. Data acquisition is totally computerized and can be maintained for whatever time interval is required, without exposing the hydrating cement to surface conditions. With this new technology, the authors will detail how cement expansion and shrinkage can be significantly different under downhole conditions of pressure and temperature than when measured at ambient conditions. It has also been observed by the authors that cement expansion or shrinkage is a dynamic process that may take many hours or even days before any significant degree of volumetric stability is achieved.

Finally, a successful field application of the new testing methodology will be presented as validation for the transfer of this new technology from the laboratory to the real world of oil and gas well cementing.
Gyrostab Project : The Missing Link Azimuth and Inclination Mastered with New Principles for Standard Rotary BHAs.
Authors: Genevois Jean-Michel , Boulet Jean , Simon Christophe , Reullon Christophe
Published: December 2007

Trajectory control in directional wells essentially requires control of only two parameters: well inclination and well azimuth. However, always tighter economic constraints and the increasing complexity of well trajectories keep setting higher challenges that demand purpose-designed and cost-efficient solutions.

The standard rotary drilling tools first used for directional drilling gave poor trajectory control. The subsequent addition of Variable Gauge Stabilizers (VGS) addressed only one side of the problem: control of inclination. Both inclination and azimuth were then mastered with Steerable Motor technology, which rapidly gained supremacy. However, there has been discontent with Down Hole Motors (DHM) for a variety of problems ranging from Rate Of Penetration (ROP), sliding mode, friction and lost-in-hole incidents to well tortuosity and hole cleaning. Jumping to rapid conclusions, one might thus think that that motors will soon be replaced by Rotary Steerable Systems (RSS).

This evolution of directional drilling techniques has led to the development of more and more sophisticated tools integrating electric and/or hydraulic power systems and loads of "embarked" electronics. The related expenditures have driven service costs to levels that are very often prohibitive for standard drilling programs and/or environments.

This paper introduces an innovative technical solution that makes it possible to control both azimuth and inclination using standard rotary Bottom Hole Assemblies (BHAs). It is based on a patented concept permitting command of Bit & BHA walking tendencies through downhole friction management at the level of a "strategic" string stabilizer.

On the basis of this concept, a joint industry project led by TotalFinaElf has successfully designed, built and field-tested a first prototype - the "Gyrostab". This missing link in the evolution of directional drilling announces the birth of a new generation of standard rotary drilling tools.
Development and Application of a Large-Hole Rotary Steerable System: Accelerating New Technology Introduction through Successful Collaboration
Authors: Armagost W. K. , Pafitis Demos , Wernig Marcus
Published: December 2007

This paper describes the successful introduction and application of a rotary steerable system for large hole sizes (17.5 and 18.25-inch.). The development of the large hole rotary steerable capability was seen to be mutually advantageous to both BP and Schlumberger. As such, this technology development was advanced as a collaborative effort.

At the outset, the collaboration team identified the technology as being suitable for the intended application. Together, team members focused on the rapid development, construction, and field-testing of the rotary steerable system. Over a 9-month period, the system was designed, tested, and deployed by teams working concurrently in the UK and the USA. Prior experience gained with smaller hole sizes was used to design the system, including both the bit and the steering unit.

The approach taken by BP asset teams in the Gulf of Mexico and Schlumberger contributed to accelerated initial field testing of the system in January 2002. Initial field trials proved successful. In its first application, the system was used to kick off from vertical, achieving a build rate of more than 3°/100 ft. Subsequently, the system has proven beneficial in other projects, and the value of the collaboration has been clearly demonstrated.
Continuous Direction and Inclination Measurements Lead to an Improvement in Wellbore Positioning
Authors: Stockhausen E. J. , Lesso W. G.
Published: December 2007

The measurement of continuous real-time inclination provides near instantaneous calculations of the build-up rate tendency of a bottom hole assembly in both rotary and slide drilling modes. The addition of an azimuthal measurement now allows for the calculation of wellbore position with this continuous data. The true nature of the wellbore curvature in slide/rotate directional drilling with steerable systems is lost when using the typical 90-foot survey interval. Continuous surveying shows this effect. When wellbore position is calculated with the continuous surveys, a significant positional discrepancy from the stationary surveys can occur.

A study was conducted using both stationary and continuous survey data from over 20 wells in Nigeria, Angola, the Gulf of Mexico, the North Sea and Indonesia. The objective was to determine the magnitude and scope of TVD positional error caused by the different slide and rotate curvatures between stationary surveys on a wide range of wells. These curvatures are not reamed out as commonly thought. They can still be seen in continuous gyro surveys taken after drilling has finished. This positional effect is not a function of the sensor accuracy, but it is a result of the environment in which surveys are measured. We show that in a horizontal well the effect can accumulate up to plus/minus 25 ft TVD. The implications of these results are far reaching. Survey positions are used in creating structure and reservoir maps, which are used in determining reserves and recovery efficiencies, and in turn for making field management decisions.

This paper highlights the results of the field studies. A review of rotary steerable system operations shows that the effect is much less than with steerable motors, but can still be of concern.

A low-cost solution for effectively determining when to slide and rotate with respect to the stationary survey is presented. This procedure results in a positional accuracy that can be maintained without changing survey data management practices.
New Drilling Technology Reduces Torque and Drag by Drilling a Smooth and Straight Wellbore
Authors: Stuart D. , Hamer C. D. , Henderson C. , Gaynor T. , Chen D. C-K
Published: December 2007

Torque and drag can be critical issues in drilling directional wells especially in extended reach drilling (ERD). During well planning, torque and drag must be projected to ensure the rig's rotating and hoisting equipment are adequately sized and to evaluate the limits for slide-oriented drilling motors. Depending upon formations, typical open hole friction factors (FF) used in simulation range from 0.22 in oil base mud to 0.35 in water based mud. These friction factors are scaled to a higher value than those measured in the field in order to account for tortuosity created by drilling assemblies.

A new drilling technology has been developed with the objective to reduce torque and drag by drilling a smooth and straight wellbore. The technology involves extended-gauge bit design with a matched steerable motor system or a point-the-bit rotary steerable system. Friction factor was studied for North Sea's wells drilled by the conventional motor systems and by new drilling systems. Significant reductions in the actual friction factors and the tortuosity index have been seen from the wells drilled by the new drilling systems.
Rotary Steerable Drilling System for the 6-in Hole
Authors: Downton G C , Carrington D
Published: December 2007

The availability of a reliable 3D rotary steerable system in 6-in. hole size opens up considerable opportunities to develop reserves where 3D steering is required, but the risks, difficulties, and delays involve in using bent housing mud motors are excessive.

On 10 April 2002, parallel field trials of a 3D, 6-in. rotary steerable system (RSS) started in Oman and the North Sea. The field trials program finished in June with more than 16,000 ft drilled and more than 400 circulating hours experience accumulated in a range of formations without failure. During these trials, the tool displayed steerability and dogleg performance suited to landing and geosteering a well in the reservoir section.

The paper outlines the principles of operation and performance capabilities of the system including the technical challenges encountered while developing a rotary steering system of this size. Field trial results from the test program are presented for a range of drilling conditions, formations, bit types, and bottom-hole assembly designs.
HP/HT Rheology of Aqueous Compressible Fluids for Underbalanced Drilling Using A Recirculating Rheometer
Authors: Kakadjian Sarkis , Herzhaft Benjamin , Neau Laurent
Published: December 2007

When drilling underbalanced, the pressure of the drilling fluid is maintained at a value below the formation pressure. In order to lower well pressure, specific low density fluids are needed i.e. gas, aerated mud or foam. Foam is particularly beneficial for drilling mainly due to its low density coupled with good carrying capability, but its use remains hazardous due to the incomplete knowledge of its bottom-hole properties and especially of its flowing properties. Predicting the pressure drop while drilling with a compressible fluid is not an easy task and for this purpose, knowledge of its rheological properties is of primary importance.

This study is part of a research program conducted in order to improve the knowledge on aqueous aerated fluid and foam properties for drilling. A specific HP/HT rheometer has been built which is able to measure rheological properties of compressible fluids under pressure (up to 50 bars) and temperature (up to 90 °C) conditions. The compressible fluid is circulated through calibrated tubing and the resultant pressure drop is measured as a function of the experimental conditions. A re-circulating set up allows to circulate the foam at a specific shear rate condition until the structure (and the resultant shear stress) is equilibrated. This is of particular importance because the structure of an aerated fluid subjected to a shear rate evolves to an equilibrated value characteristic of a steady state, doing measurement on an structure evolving fluid is indeed non valid. A visualization cell coupled to an image acquisition device permits to characterize the structure of the foam in parallel to the rheological measurement.

Experiments were performed with a specific foaming system already used on site for drilling application. Rheological evaluations at several pressures, temperatures and fluid qualities were investigated. Existing model were tested and showed their limits. Interpretations of the data incorporating the importance of foam structure are proposed to help building a coherent model. These measurements allow a better understanding of the compressible fluid properties under pressure and temperature conditions and will be extended in a near future with reservoir fluid contamination experiments.
Asphaltene Deposition Prediction and Control in a Venezuelan North Monagas Oil Field
Authors: del Carmen García María , Henríquez Magaly , Orta José
Published: December 2007

Asphaltene deposit formation is a severe problem frequently faced during crude oil production and transportation, that affects the reservoir, production tubing and surface facilities, depending on the stage where this critical point is reached. This point corresponds to the pressure at which asphaltene particles start to form. This value is directly related to the oil physical chemical stability. When flocculation pressure is reached into the reservoir, severe formation damages occur due to asphaltene precipitation in the porous media, evidenced as wettability and/or relative permeability alterations. When asphaltenes precipitate in the production tubing, refractory plugs reduce or even stop crude oil production until chemical/mechanical removal is performed. The stability of several crude oils produced in a North Monagas oil field (Carito) from Venezuela, in terms of asphaltene deposition, was evaluated to predict their behavior and prevent future plugging. "Spot Test" and n-heptane titration (asphaltene flocculation onset determination under atmospheric conditions) were used as crude oil stability criteria. Solid deposits, from these wells production tubing and surface facilities, were characterized in order to establish if their origin was organic (asphaltenes or paraffins) or inorganic (scales or sand), and to confirm the stability results assessed in the first set of experiments. Once the asphaltene problem was identified, several commercial asphaltene inhibitors were evaluated, considering their efficiency when a fixed dosage of these products was added to the studied crude oils. Dead oil n-heptane titration of treated crude oils allowed identifying the products that induced higher flocculation onsets when compared with untreated sample results. A second condition that was evaluated for inhibitor selection, was the product thermal stability, considering that downhole treatments would require to face temperatures as high as 150°C. Results of some practical applications derived from this evaluation are presented in this work.
Steamflood Surveillance in Sumatra, Indonesia and San Joaquin Valley, California Using Steam Identification, Carbon/Oxygen, and Temperature Logs
Authors: Zalan Thomas A. , Badruzzaman Ahmed , Julander Dale , Whittlesey Karen
Published: December 2007

ChevronTexaco has developed leading edge data acquisition and interpretation strategies to monitor steamfloods in Sumatra, Indonesia and San Joaquin Valley, California. This paper reviews ChevronTexaco's current steamflood surveillance techniques, and how learnings from San Joaquin Valley are adapted to operations in Sumatra.
Risked Reserve Estimates for Complex Prospects
Authors: Skates Jeff
Published: December 2007

To find oil, drill near an oil field - the cheapest and lowest risk reserves are commonly found as extensions of existing fields, or updip from "near-miss" exploration wells, or simply in prospective acreage which has had many prior discoveries. In these cases, there is more well control and some risks have already been eliminated or minimised compared to the traditional wildcat. The most attractive prospects may also have stacked pay or other multiple targets. In either case, to best estimate the risks and rewards involved in developing these resources, attention to detail is required. Proper accounting for dependencies among different risk factors is required, in order to evaluate the overall risk, the risked reserves distribution, and thus the economic value. The techniques can be extended to value a prospect portfolio, accounting for common or related risk elements.
Reliable and Cost Effective Reservoir Characterization of Thin, Layered and Heterogeneous Reservoirs: Case Studies
Authors: Singh C. S. , Singh J. , Baruah N. , Neog P. K. , Talukdar B. N.
Published: December 2007

In this era of cutting-edge technology where stochastic and geostatistical modelling is the order of the day, conventional layer-cake modelling for highly heterogeneous reservoirs in two fields have yielded very good results. The performance predictions of reservoir simulation studies based on the conventional geological model of these fields are in close conformance with the actual production behaviour thus substantiating the efficacy of such type of modelling.

The results of these studies recommended that additional wells be drilled for augmenting production and recovery. Mapping of advancing edge-water front from simulation based on the 3D seismic derived geological model helped in optimal positioning of the development well locations. Although the role and accuracy of geostatistical and stochastic modelling can not be denied, conventional layer-cake modelling, within certain limitations, is a fairly reliable and cost-effective reservoir characterization tool.
Unusual Carbonate Rocks Showing Increasing Trends for Rock Compressibility as the Applied Net Stress Increases
Authors: Sadeghazad Ayoub , Beiranvand Bijan
Published: December 2007

Pore volume compressibility is a major energy source for the naturally depleting reservoirs. A good estimate of pore volume compressibility is necessary for proper simulation of dynamic reservoir modeling. Therefore, a detailed study and investigation must be done to understand and quantify the rock compressibility influencing parameters.

The main objective of this paper is to evaluate and discuss the influence of geological and petrophysical parameters such as rock texture, grain fabric, porosity type, grain density, and pore size distribution on the pore volume compressibility.

Compact tests using CMS-300 equipment and pore volume compressibility tests were performed on more than 100 core plugs taking from upper Cenomanian Sarvak formation (equivalent to Mishrif formation). This formation is mainly a non-vuggy and non-fractured carbonate reservoir rock. The tests have been carried out under several net stresses during increasing and decreasing stress cycles. The calculated compressibility data mainly follow the major trends including: steadily decreasing, sharply decreasing followed by constant line, and increasing trend.

Obviously, the compressibilities following the increasing trend line, which is the unusual case, is the most interesting part of this discussion. In addition, other techniques and experiments such as mercury injection, SEM, rock type evaluation, gamma ray log, and natural gamma ray spectroscopy method have been applied on some of the samples, especially on samples with unusual trends, to understand the mechanism in which show unusual compressibility trends.
Advances in Horizontal Oriented Perforating Optimize Perforating and Production While Maintaining Borehole Stability
Authors: Benavides Simon P. , Myers William D. , Van Sickle Edgar W. , Vargervik Kristian
Published: December 2007

Perforating in highly deviated or horizontal wells presents any service company with a serious technical challenge. Attempting to maintain wellbore and perforation tunnel stability by perforating in the direction of maximum stress compounds the complexity of the perforating job. Ensuring that orientation remains valid while navigating through severe doglegs requires detailed pre-job design planning supported by applicable research data.

This paper discusses advances in horizontal oriented perforating in long horizontal sections designed to optimize perforation efficiency and production. The techniques and results discussed are applicable to any horizontal or highly deviated well where orientation of charges to maintain wellbore stability is critical. New developments to navigate through severe doglegs and maintain orientation are significant contributions to perforation technology. Some of the results and experiences encountered while performing an oriented perforating job in a 2246-m horizontal section of a well in the North Sea for a major operator are also discussed in this paper. A world record was set by perforating a total of 1496 m of the horizontal section in a single trip with orientation successfully verified. Additional discussion on the testing and research that preceded the job is presented.

As demonstrated in positive results from the North Sea case history, perforating with oriented charges in horizontal sections will play a key role in the future to assist operators increase and optimize production from new or declining fields.
An Alternative Wellbore Stabilisation and Sand Control Technology – Application of Expandable Sand Control System in Ulti-lateral Wells
Authors: Wang J. L. , Ren G. , Aitken S. , Yuan M.
Published: December 2007

The Xijiang field lies offshore China in the South China Sea and is operated by Phillips China Inc. The reservoir is unconsolidated and requires sand-control, however conventional sand-control techniques are complex when applied to multi-lateral well completions. The expandable sand control system offers an alternative, which combines a larger final wellbore diameter and zonal isolation whilst being simpler to install in multi-lateral well completions.

The field is, now mature and water-cuts have increased, making the use of horizontal well technology attractive in order to enhance the production rate, minimize drawdown and maximise the recovery by deferring water coning. Furthermore, the limited remaining reserves and drilling slot constraints meant that multi-lateral wells were the most attractive option for further development of the remaining reserves and improving ultimate recovery.

This paper discusses how due to the nature of the wells, the requirement for wellbore stabilization and zonal isolation resulted in the selection of Expandable Sand Control technology to complete the reservoir.

In this case study multi-lateral well, the main bore is a three zone lateral with a total of 299m Expandable Sand Screen (ESS) across the target reservoir and 69.5m Expandable Isolation Sleeve (EIS) across water-bearing sands and shale. The top zone is a cased hole completion and the lower two zones are open hole completions. The other lateral branch has 930m of 7" liner running inside the horizontal open hole followed by 347.5m ESS. The installation of this sand control completion combined with multi-lateral technology is then detailed and the lessons learned discussed.

Finally, the post-production well performance data is compared and contrasted with previous wells to demonstrate the improvement in productivity achieved with this new method for wellbore stabilisation of the horizontal wells in poorly consolidated reservoirs. Initial production data shows the well to produce 6,900bpd oil with only 5% water cut which is 2-3 times more than the previous wells completed with traditional sand control methods at the same production drawdown.
Addressing Common Drilling Challenges Using Solid Expandable Tubular Technology
Authors: Andrews Stacey , Keel Doug
Published: December 2007

Maximizing hole conservation while optimizing well economics in both conventional and deepwater wells is a continual challenge. Solid expandable tubular systems address this challenge and others by applying technology that provides significant solutions.

Solid expandable tubular systems have been installed in both openhole and cased-hole wellbores since November 1999. These installations occurred in a variety of well environments on land, offshore, and in deepwater to solve a myriad of drilling and completion challenges.

This paper will discuss case histories in depth by describing drilling challenges surrounding the use of solid expandable tubular technology and the conditions leading to the use of this technology.
New Setting Technique for Gravel Pack Packers Increases Operational Safety and Reduces Costs
Authors: Dawson Mark E. P. , Smith Marshall N.
Published: December 2007

In the typical life cycle of a given well, the majority of the budget is generally allocated to the drilling phase with the remainder to cover the completion costs. If, however, these stages are not kept within planned budget and time parameters, it becomes critical to reduce the time and cost in the final completion strategies to enable the budgeting of the project to be successful. This paper will discuss a new method for setting a gravel-pack packer that can assist in reducing the overall time associated with the completion phase of a well bore, and in turn, the subsequent cost.

Packers are traditionally set by dropping a setting ball into the workstring to create a plug in the service tool that is either pinned or threaded to the gravel-pack packer. The plug is subjected to an applied pressure that is translated from the service tool to the packer, which both begins and finishes the packer setting process. The creation of this plug, ball on seat, is affected by several factors. Such factors are wellbore geometry and deviation, the type of completion fluid, and the packer setting depth. Each of these factors relates directly to the time needed to create the plug, the ball landing on seat, and in certain instances, the time needed to reverse the setting ball out of the work string. Again, the time to drop and/or reverse the setting ball all affect operational times.

The new technology available eliminates the time and risk associated with using setting balls against which pressure is traditionally applied to set gravel-pack packers. As the system is hydrostatically driven, it allows a constant hydrostatic pressure to be maintained on the formation, reducing the risk of formation collapse, surges on the formation seen when shearing the ball seat out, and the risk of the ball seat shearing prematurely. With fewer completion operations, chances for misruns are reduced, and safety and environmental risks are minimized. The reduction in setting time allows this system to be considered a viable and affordable option for wells that meet the necessary criteria. The cost savings are even greater in offshore environments.