bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Flow Simulation in Discrete Fracture Network Models
Authors: Basquet Rémy , Jeannin Laurent , Lange Arnaud , Bourbiaux Bernard , Sarda Sylvain
Published: December 2007

Advanced characterization methodologies are now able to provide realistic pictures of fracture networks. We recently developed a software to simulate the transient and pseudo-steady-state flows of a slightly compressible fluid in Discrete Fracture Network (DFN) models. This simulator is used to validate the fracture network geometry and to calibrate the hydraulic properties of the fractures via dynamic data obtained from flow meters, interference and well tests. This paper is dedicated to the extension of the methodology to gas cases, taking into account the high fluid compressibility and the non-Darcian effects near the well bore.

The main specific features of our simulator are described and illustrated through demonstrative examples. Our DFN simulation approach is based on an optimised explicit representation for both matrix and fracture media and a specific treatment for matrix-fracture and matrix-matrix exchanges. A pseudo-pressure function is included in the diffusivity equation to take into account highly compressible fluids. The hydrodynamic behaviour of gas fluid flow near the well bore is taken into account via a skin effect proportional to the flow-rate for both matrix-well and fracture-well transmissivities.

This innovative numerical simulator is validated against existing analytical solutions and compared with finite-volume solutions computed with a suitable grid. Then, for application purposes, a complex realistic case involving a multi-scale natural fracture network with small-scale fractures and major objects such as seismic and sub-seismic faults is presented. An interference test is simulated on a representative DFN model and on the equivalent dual-porosity model built thanks to up-scaling procedures. This up-scaled reservoir model is shown to remain consistent with the geological DFN model in terms of gas flow. This example illustrates the practical use of DFN models in our fractured reservoir modelling workflow.
A Shared-Memory Parallel Black-Oil Simulator with a Parallel ILU Linear Solver
Authors: Collins David A. , Grabenstetter James E. , Sammon Peter H.
Published: December 2007

A parallel adaptive-implicit black-oil reservoir simulator is described which is designed to run on shared-memory machines with the parallelism controlled by OpenMP calls. The basic design decisions leading to this choice are discussed. The changes which were required in the original non-parallel black-oil simulator to achieve parallel execution are discussed, as are the techniques for achieving good parallel speedups for simulator tasks such as building the Jacobian matrix.

The simulator uses a parallel implementation of a variable degree incomplete LU (ILU) factorization followed by a parallelized GMRES iteration to solve the linear system of equations associated with the Jacobian matrix. The techniques for achieving this parallelization are discussed, as are techniques for load-balancing some solver sub-tasks. The effect upon the ILU preconditioner of the reservoir decomposition needed to achieve the solver parallelization is discussed and techniques for reducing this effect by reordering within domains are examined.

The simulator has been tested on a variety of simulation problems and a number of 32-bit and 64-bit shared memory computers, with the number of processors used varying between 1 and 32. The speedups obtained are presented and analyzed, and the problems entailed in applying the simulator to very large problems (ten million to more than one hundred million active cells) are described. Results are presented for several simulation scenarios as run on several different computers.
Through Bore Drilling Systems: a New Drilling Option
Authors: Runia John , Murphy Eugene , Boyes John , Sutherland George , Sim David , Brown Paul
Published: December 2007

This paper describes a Through Bore Drilling and Logging System, which has been developed and tested over the past four years with increasing levels of success.

The key components of the system, as it stands today, are: A PDC bit with a removable and re-insertable 2 ½" ID center insert and latching mechanism.A string of memory logging tools (gamma, resistivity, density, neutron and sonic measurements) with 2 ¼" OD.A 3D rotary steering device, with 2 ½" full through bore.A removable and re-insertable MWD probe type tool, which leaves a 2 ½" full through bore after retrieval.

The trials and jobs carried out to date are also briefly described, together with the currently perceived strengths and weaknesses of the current system.
Quality in HSE Management Systems
Authors: Prewitt Annette
Published: December 2007

This paper describes Quality's role in HSE systems and provides detail information on one offshore drilling contractor's HSE system through the company's quality system, Global Excellence Management System (GEMS). Quality tools used in HSE systemElements/main areas of the management system and integration with HSEComparison of international standards and regulatory requirements for HSE & Quality. MMS SEMPIMO ISM CodeISO 9001:2000ISO 14001API Spec Q1Malcolm Baldridge National Quality Award Program: 2002 CriteriaWorkforce involvement and implementation to meet system objectivesUse of Best Practices in development of a global system for MODUs.Importance of a Balanced Scorecard

Presented in this paper is an evaluation template for assessing a company's system compliance and key results in several performance measures for HSE.
Ultimate Capacity of a Disposal Well in Drilling Waste Injection Operations
Authors: Abou-Sayed Ahmed S. , Guo Quanxin , Meng Fanhong , Zaki Karim
Published: December 2007

Drilling waste disposal through downhole hydraulic fracturing is often the preferred waste management option because it can achieve green operation and often has favorable economics. Most field situation comprise of injection in either dedicated well or in the annulus of an existing well. Containment of the disposed waste must be ensured and one of the questions in drilling waste injection operations is what the capacity of a disposal well or annular scheme is? The answer to this question depends on downhole waste storage mechanisms. It is evident from laboratory simulation studies and field operation experience that multiple fractures are created in drill cuttings injection (DCI) operations and the capacity of a disposal well is much larger than that estimated from single fracture simulations. More importantly, as more solids are injected into the disposal formation, the local stress is modified. Because of this change in local stress, fracture shapes and extents at the beginning of a DCI operation can be significantly different from the fracture shapes and extents at the end the operation. Modeling of this fracturing evolution process is necessary and essential to ensure the safe containment of the disposed waste and to estimate accurately the disposal capacity of a drilling waste disposal well.

This paper presents a numerical algorithm for modeling the multiple fracturing and fracture evolution process during drill cuttings injection operations. Case studies show that the modeling results based on multiple fracturing have significant impacts on DCI operations engineering such as injection pressure requirement and disposal capacity. The results also provide insight into best practices for the containment of disposed waste, when injection can continue into a previous zone and when is there a need to inject into a different zone or when a new disposal well should be drilled. For the purpose of brevity, "disposal well" will be used to designate either a dedicated injector well or an annular injection scheme.
Challenges of Drilling an Ultra-Deep Well in Deepwater – Spa Prospect
Authors: Rohleder Stephen A. , Sanders W. Wayne , Williamson Roger N. , Faul Gary L. , Dooley Lynn B.
Published: December 2007

Conoco drilled the Spa Prospect, Walker Ridge 285 #1, in the Gulf of Mexico to a depth of 29,452' MD / 29,434' TVD. The Spa Prospect was a subsalt well encountering approximately 9,981' of salt. The Transocean Deepwater Pathfinder, a dynamically positioned drillship, was utilized to drill this well in 6,654' of water. Original planned total depth for the well was 31,600' MD / 31,000' TVD. This represented one of the deepest wells ever planned in the Gulf of Mexico. All geologic objectives were reached by 29,452' and drilling operations were terminated.

This paper describes the challenges involved with planning the well, documents the execution, and concludes with lessons learned. The well planning included the following: Location selection criteria for avoiding shallow hazards while meeting geological objections,Pre-drill pore pressure and fracture gradient estimation,Hydraulics design and its relationship to drill string selection,Casing and wellhead program objectives,Landing string design,Lost circulation assessment,Mitigation of annular pressure in trapped annuli, andThe implementation of test rams to reduce BOP testing times.

The execution section of the paper describes experiences encountered and the technologies utilized.
Magnolia Casing Design for Compaction
Authors: Ibekwe I. A. , Coker O. D. , Fuh G. F. , Actis S. C.
Published: December 2007

ConocoPhillips' Magnolia project will utilize a Tension Leg Platform (TLP) in a record water depth of 4674 feet (1425 m) in Garden Banks block 783 in the Gulf of Mexico. The wells will be predrilled and then completed with a platform rig. Production is expected from unconsolidated, fine grained and over-pressured Pleistocene and Pliocene formations. Reservoir compaction was identified as a drive mechanism for the field. Rock mechanics studies indicated that reservoir depletion in the low-strength and high-porosity reservoir rocks could result in significant reservoir compaction due to initial shear failure followed by pore collapse. This paper will describe our analysis of such rock failure mechanisms and projected strains, which served as the basis for deriving estimates for reservoir compaction and stretch of overlying strata.

The team faced a unique challenge to develop a casing design that would address reservoir compaction concerns. By itself, casing design was only one part to a solution that involved developing a comprehensive well construction and completion strategy that could deal with the reservoir compaction problems. The cost of casing failure would have significant negative impact on project economics.

A concerted effort was undertaken to study the geology and the rock characteristics of the formations in this field. The resulting casing design strategy conforms with, and in some aspects improves upon, ConocoPhillips' current casing design philosophy. This paper discusses two of the major design factors: 1) the effect of tension on the casing in the overburden above the reservoir and 2) the effect of compression on casing in the reservoir. Specific design criteria were developed for each of these factors. The field was sub-divided into different reservoir compartments, then the maximum stretch and compressive strain that is expected in each compartment was calculated for the reservoir and overburden zones.

The selected design strategy was applied to the casing design with a view to optimizing wellbore life and project economics of each well. The result is a unified approach to compaction that begins in geomechanical analysis and ends with the financial decision process.
Subsea Abandonment From Semi With Surface BOP
Authors: Norwood Edwin B. , Chinoyerem Njoku , Ranyis Victor
Published: December 2007

Sub-Sea Abandonment With Surface BOP. Baram 8 (BA-8) consists of a single well in 179 feet of water supported by a wellhead protection jacket in the Baram Field. The well was drilled in 1968 and the jacket was installed later in the same year, both of which collapsed in 1975, pulling both the conductor and the riser with it. The collapsed structure resulted in distortion of conductor and casing strings at the seabed. The well was in normal production mode, producing less than 0.2 MMscf/d of gas at the time of collapse. The subsea safety valve closed, thus preventing hydrocarbon release after the collapse. In September/October, 2001, the conductor and casing strings were cut to a depth of 18 feet below seabed, leaving the remaining casing shape non-circular. Deeper excavation was not possible at that time due to limitations of the jack-up in use.In July 2002, the Atwood Falcon, a semi-submersible drilling rig, was equipped to excavate some 30 feet below seabed using the latest in seabed excavation equipment. The Jet Prop tool uses a large propeller to push a high volume column of water vertically downwards onto the work area. This brings the seabed material into suspension and disperses it from the work area.The Jet Prop was able to create a large excavation around the wellhead with stable side slopes for safe diver operations. The soil from the excavation area was dispersed laterally across the seabed by operating the Jet Prop while manoeuvring the rig on its moorings. To support the cutting of conductor and casings some 30 feet below the seabed, a full saturation (SAT) dive system was installed on the riser deck. This allowed continuous diving without weather shut down.

After cutting the conductor and casing, a 30-inch conductor was installed to the surface. A used Permanent Guide Base was modified and installed on the rig's spider beams to serve as a "false rotary". Space out of 30-inch conductor connection was designed to allow a 10-foot "stroke". The rig's spider beams provided lateral support.

A 13 5/8 × 5000 psi ram/annular surface BOP (SBOP) was prepared in Singapore. The SBOP, placed on top of the 30" conductor, was located in the rig's cellar deck. Circulation returns were completed through a jack up-style bell nipple.

The existing semi-submersible BOP control pod and choke & kill (C/K) lines were used on the SBOP for easy installation and control.

In order to have effective operation, all the various components were pre-fabricated while the rig was drilling. The SAT dive system was installed and commissioned prior to arrival at BA-8. The pipeline burial equipment, Jet Prop, was air freighted to Singapore and assembled in the cellar deck. This equipment was powered with the rig's mud pumps. The SBOP was assembled into a special frame to use the rig's subsea Koomey pod in a surface-mounted upper female for SBOP control. Existing C/K lines were connected to the SBOP using No. 5 Cameron Hubs.

After the initial set-up, the P & A procedure followed a normal program.
Performance Gains with 5th Generation Rigs
Authors: Keener Chip , Keji-Ajayi Ibukun , Allan Rod
Published: December 2007

Transocean's fleet of newbuild, deepwater, 5th generation rigs have accumulated an aggregate 35 rig years work experience. Among the exceptional accomplishments: deepest water depth (2,966 m / 9,727 ft – Unocal Discoverer Spirit)deepest subsea completion (2,198 m / 7,209 ft – Unocal Discoverer Spirit)deepest moored operation (2,442 m / 8,009 ft – Shell Deepwater Nautilus)simultaneous well test / crude storage / offload – (BP Discoverer Enterprise)

The rigs are showing significant performance gains, some of this attributable to dual or off-line activity, and some in benefit of higher specification equipment (pump pressures, flow rates, etc). Many among the operator community are now factoring generous premiums for these efficiencies in their bid evaluations. In confirming and assessing the gains, Transocean have undertaken a modeling exercise, comparing the performance of 5th generation rigs with earlier builds. Representative performances have been distilled from the IADC Reports, such that well curves can be predicted and compared for each of the rig classes.
Dropped BOP Stacks: Understanding Causes to Improve Prevention
Authors: Sattler Jeffry P.
Published: December 2007

Although thankfully not a common occurrence, when a BOP stack is dropped, it is most often a catastrophe. With the understanding of the causes of dropped stacks provided in this paper, one will be able to identify specific steps to minimize the likelihood of this type of failure on future projects in any floating drilling operation.
Aphron-based Drilling Fluid: Novel Technology for Drilling Depleted Formations in the North Sea
Authors: White Craig C. , Chesters Adrian P. , Ivan Catalin D. , Maikranz Sven , Nouris Rob
Published: December 2007

Drilling depleted reservoirs is fraught with a host of technical and economic problems that often make it unprofitable to further develop some mature fields. Most of the problems center around uncontrollable losses and differential sticking. Frequently, less expensive drilling fluids will be used in a particular interval, even though it may have the propensity to damage the formation. The reasoning holds that such fluids will offset the high costs of losing more expensive muds to the formation. If operators turn to underbalanced drilling as an alternative, the extra time and equipment required for a safe operation can seriously degrade project economics in some applications.

A specialized invasion-control drilling fluid has been developed to drill reservoirs prone to lost circulation. This fluid combines certain surfactants and polymers to create a system of micro-bubbles or aphrons that are encapsulated in a uniquely viscosified system.

Aphron based systems are engineered drilling fluids that aid in well construction by controlling losses in depleted, high-permeability sands while stabilizing pressured shales or other formations. One of the more attractive features of an aphron-based system is that it does not require any of the extra equipment used in air or foam drilling. There are no compressors, high-pressure hoses or connections to add costs and safety concerns. The system uses conventional fluid-mixing equipment to form tough, flexible micro-bubbles.

This paper describes the development and application of the specialized micro-bubbles-based drilling fluid for controlling downhole mud loss in a depleted reservoir in the North Sea. The key issues of this project were excessive overbalance drilling conditions (> 5,000 psi) leading to the risk of highly expensive lost circulation and open perforations in the upper producer, requiring temporary sealing during drilling. The well was successfully drilled to TD without any drilling fluid losses. The authors will detail the laboratory methods used to generate appropriate formulations, the operational procedures, and field application.
Transient Gel Breaking Model for Critical Wells Applications with Field Data Verification
Authors: Bjørkevoll Knut S. , Rommetveit Rolv , Aas Bjarne , Gjeraldstveit Helga , Merlo Antonino
Published: December 2007

The paper addresses the problem of predicting pressure peaks when starting pumps after a static period while drilling a well. It demonstrates that laboratory measurements with standard Fann viscometers and a gel breaking model can be used for predicting such peaks.

Fluids with properties that are similar to those of real drilling fluids have been studied in detail in the laboratory. Gel breaking and thixotropic behaviour were first analysed in detail through rheometer measurements. The fluids showed a pronounced time dependent behaviour. Afterwards each fluid was placed in a flow loop where circulation was started after a static period. The time dependent signals were logged and analysed. An initial sharp pressure peak followed by a slow decrease in pressure was typical.

A local model based on rheometer measurements that predicts gel breaking pressures versus time is presented. The authors are not aware of any other such model.

The local model has been integrated in a transient drilling simulator which predicts the pressure peaks that follow when starting pumps after a static period. Gel strength is broken successively from the pump, down the drill string, and up the annulus. The model will help drilling engineers to determine whether extra care is required when starting pumps

Controlled field measurements have been made in two North Sea HPHT wells, one with water based and one with oil based drilling fluid. Gel breaking pressures were measured when starting pumps after static periods of different lengths. The effect of rotating the drill string prior to pumping was tested.

The transient model reproduced measured data with reasonable values of gel model parameters.

The observed effects are expected to be of importance when drilling any critical well, which may be deep water, HPHT, or extended reach wells.
Imaging Unstable Wellbores While Drilling
Authors: Edwards Stephen , Matsutsuyu Bruce , Willson Steve
Published: December 2007

This paper presents a case study of borehole instability from 4 wellbores on the Gulf of Mexico (GOM) shelf, offshore Louisiana. Logging while drilling (LWD) borehole images are combined with observations of cavings and modeling of borehole shear failure in order to diagnose the mechanisms of instability and thus select the appropriate remedial action.

It is observed that instability due to shear failure of intact rock (borehole breakout) can be suppressed by increasing mud weight. However, where pre-existing planes of weakness such as bedding planes and fractures dominate the mechanism of instability, mud weight increases do not necessarily lead to a more stable hole and can in fact further destabilize the wellbore.
Poroelastic Effects on Borehole Ballooning in Naturally Fractured Formations
Authors: Helstrup Ole A. , Rahman Khalil , Chen Zhixi , Rahman Skeik. S.
Published: December 2007

This paper presents a study on wellbore ballooning and (in)stability in naturally fractured formations. A model containing a single fracture is analysed using a poroelastic numerical approach for a number of in-situ stress ratios and rock matrix permeabilities. It was found from this study that the stress response for this system depends not only on the in-situ stress, but also on rock matrix permeability and time. The results are compared with that from an analytical linear elastic solution approach, and it is shown that the results are significantly different.
Well Control Considerations – Offshore Applications of Underbalanced Drilling Technology
Authors: Hannegan Don M. , Wanzer Glen
Published: December 2007

This paper focuses upon the well control aspects related to offshore applications of the tools and technology normally associated with underbalanced drilling systems (UBS). A discussion of the history of underbalanced drilling and the evolution of the specialized equipment required to practice the technology with a well established and commendable well control track record will help one recognize the potential benefits of offshore application. Whether onshore or offshore, a key component of UBS is a rotating diverter control head (RCH). As a key tool, the development of RCH's enabled the technology of onshore UBD and led the way towards encouraging the development of numerous other pieces of the UBS "tool chest". RCH's are fulfilling the same enabling role offshore, including leading the way towards numerous non-underbalanced drilling uses. Offshore applications of the tool include "onshore models" atop surface blowout prevention stacks (BOP's). Several "offshore variations" of the tool enable deepwater drilling (subsea BOP) with lightweight fluids, managed pressure drilling, dual gradient deepwater drilling, slim riser deepwater drilling with a surface BOP, and one subsea model facilitates controlling abnormally pressured aquifers and/or achieving zero discharge when riserless drilling top hole sections when establishing a subsea wellhead.

Barriers to achieving a true state of underbalance during an offshore well's drilling program include wellbore instability, dealing with produced hydrocarbons, and in some cases, regulatory restrictions. Offshore applications were the intent in using UBS was to drill ahead under a true state of underbalance now total around 100 wells. All but one has been drilled from rigs a surface BOP's. In deeper waters from floating rigs with subsea BOP's, the trend to drill underbalanced is expected to be more aggressive in the future given the large percentage of all known deepwater resources being economically undrillable otherwise.

In the nearer term, non-underbalanced drilling applications of the specialized equipment and technology associated with underbalanced drilling is much less of a step-change and avoids the aforementioned barriers to true underbalanced drilling offshore.

Therefore this discussion places emphasis upon the non-underbalanced drilling applications of the specialized equipment associated with underbalanced drilling and illustrates the well control considerations.

In the context of this paper, well control implications relate to the potential for surface events as well as underground blowouts.
Cuttings Transport with Foam in Horizontal & Highly-Inclined Wellbores
Authors: Ozbayoglu Evren M. , Miska Stefan Z. , Reed Troy , Takach Nicholas
Published: December 2007

Foams are of considerable interest for annular pressure management in many drilling applications. While foam rheology and hydraulics have been studied in the past, knowledge of cuttings transport with foam is very limited for vertical wells, and even less well understood for horizontal and inclined-well configurations. In this paper, cuttings transport with foam in horizontal and highly-inclined wells is analyzed.

Using the principles of mass and linear momentum conservation, a model consisting of three layers (motionless bed – observed in most experiments, moving foam-cuttings mixture and foam free of cuttings) is presented. The model includes seven independent equations and seven unknowns. A computer simulator was developed to solve simultaneously the system of equations for flow velocities, cuttings bed height, slip velocity, the in-situ concentration of flowing cuttings and pressure drop.

An extensive experimental program on cuttings transport was conducted using The University of Tulsa Drilling Research Projects' full-scale (8" by 4 ½") flow loop at 70° to 90° inclinations (from vertical). A broad range of annular velocities and cuttings injection rates was investigated using foam qualities of 70% to 90%. Results from the experiments are presented in the form of graphs showing the cuttings bed cross-sectional area and pressure losses vs. foam flow rate. In all experiments, the foam behaved as a pseudo-plastic fluid; foam qualities of 80% and 90% exhibited noticeable wall slip. At a given flow rate and rate of penetration, bed thickness increases with an increase in foam quality. There is little effect of inclination angles in the range of 70°–90°.

The experimental data were used to verify results from the simulator. The simulator is capable of estimating bed thickness and pressure drop with an error of less than 20% in most cases.
Reducing Development Cost in Forcados-Yokri Field with Application of Slim Well Technology
Authors: Erivwo O. E. , Okwa H. D. , Ideh M. A. , Aduba A. A. , Woodland D. C.
Published: December 2007

The plans for re-developing the mature Forcados-Yokri field in the shallow offshore area of the Niger Delta was conceptualized as an integrated project with a fixed and delegated budget for wells delivery. However, with the upbeat in global drilling activities, resulting from increase in oil price, rig rates for the jack up rig in use was increased by 100% and was set to jeopardize the project economics for the campaign. This implied the delivery of less wells than planned for the available budget, with the resultant effect on reserves developed in the field, and thus required something different to deliver step change reduction in well construction costs. Several innovations aimed at improving drilling performance such as cluster and batch drilling, conductor driving optimization e.t.c. were implemented in the face of a flattening learning curve as the drilling campaign progressed, the most significant being the adoption of slim well technology.

This paper presents the application of "slimline" wells in the Forcados Yokri Integrated Project (FYIP). It reviews the economic and technical justification for the phased implementation of the technology over the well clusters in the FYIP campaign beginning with a field trial (TXZK-4). It emphasizes on the planning, project management, concept selection, risk mitigation and critical engineering considerations applied to address the numerous concerns associated with a largely restricted contingency envelope from slimming down to a 7" surface casing and 4–1/2" completion liner in the horizontal section, the technical limit for telescoping well configurations.

The paper concludes with highlights from the execution phase – problems encountered, learning points and – and the resultant cost impact on the FYIP drilling campaign.
A Novel Approach to Access Trapped Reserves below Highly Depleted Reservoirs
Authors: Donaldson Sonja J. , van de Weijer Tony A. H. , Chesters Adrian P. , White Craig C.
Published: December 2007

In mature fields, hydrocarbons may become "trapped" below the main production zones. These overlying formations may be produced to a very low pressure, while the smaller trapped reserves may remain at virgin pressures or be slightly depleted. Drilling the depleted reservoirs requires a low mud weight to prevent losses and avoid either lower reservoir influx or shale collapse. Due to the often marginal size of the trapped reserves, reducing well costs is critical to project economics. One obvious solution is to deepen an existing producing well and commingle the production from the reservoirs, thus reducing cost when compared to a new dedicated well. Three novel technologies have been identified that, when combined, would allow wells to be deepened at low cost and without severe losses. These include through-tubing drilling, aphron-based drilling fluid, and real time ECD modelling.

This paper describes a project where these technologies were applied. Owing to the high-risk nature of the project and the need to protect existing production from the chosen well, in-depth planning and staged implementation of the new technologies were undertaken. A comprehensive risk management procedure was developed and careful testing and data gathering undertaken. The well was successfully executed within planned time. The authors will outline the theoretical and practical aspects of the technology selection criteria, risk management aspects, and how all these were combined to deliver a successful well.
Stacked Multilateral System for the Troll Olje Field – Development and Case History
Authors: Cuthbert Andy , Hegreberg Jofrid M. , Skoglund Elisabeth
Published: December 2007

In response to the need to drain more of the reservoir within the Troll Field, especially from low permeability mica-sands where production levels are low, the current dual lateral technology was advanced to include two lateral legs in addition to the mainbore by creating a stacked or trilateral system.

Based on a conventional multilateral ITBS™ (Isolated Tie-Back System), two 9 5/8-in. liner joints — incorporating pre-milled windows and pre-installed latch couplings — are installed a specific distance apart but aligned to the same orientation. After installation of the windows and subsequent installation of the mainbore screens, a whipstock is latched into the lower coupling and the lower window opened up to drill the first lateral leg. To complete this section of the well, the whipstock is retrieved, replaced by a deflector over which a flexible hanger with D-section legs is installed to create the junction. One leg is attached to the lateral screens whereas the other leg is connected to a seal stinger. The flexible hanger is oriented to enable the stinger to land in a seal stack in the deflector thereby creating the means of communication with the main bore. Drilling out and completion of the upper lateral is a duplication of the lower lateral with some exceptions.

This paper will discuss the factors leading to the development of the trilateral ITBS™, its installation and the impact on Troll Olje Field drainage.
The Twist and Shear of Helically Buckled Pipe
Authors: Mitchell Robert F.
Published: December 2007

The effect of torque on buckling was first recognized in the design of hollow propeller shafts for ships. If buckling could be caused by torque, then perhaps torque could be induced by helical buckling. This effect has not been extensively studied because the assumption has always been that the effect was too small to be of concern. This problem required an exact large-displacement solution to the helically buckled pipe, since conventional small displacement analysis has built-in the assumption that these effects are not important.

How significant are these effects? In Lubinski's paper on helical buckling, he works a sample problem of a squeeze cementing operation in 2–7/8" 6.5 ppf tubing. The induced torque due to helical buckling may exceed make-up torque (in the range of 600–2300 ft-lbs depending on grade) for large radial clearances, so induced torque in this problem may be high enough to break the connection!

This paper will give complete details for the torque and shear calculation in the appendix of this paper. The body of the paper will examine several typical tubing load situations to evaluate the effect of induced torque and shear on conventional design.
Performance Driven Drilling Tubular Technologies
Authors: Chandler R. Brett , Jellison Michael J. , Payne Michael L. , Shepard Jeff S.
Published: December 2007

New developments in drilling tubulars are rapidly evolving and represent enabling technologies for the industry's continued advancement of drilling deeper, longer reach wells more cost effectively. This paper presents key tubular technologies including metallurgical and manufacturing advancements that have enabled high strength, high toughness drill pipe. Application specific landing string designs that provide substantial advances versus conventional designs are presented and analyzed. Field performance of 5–7/8 in. drill pipe is also presented.
Subsea Accumulators – Are they a False Reliance?
Authors: Curtiss Jason P. , Buckley Margaret
Published: December 2007

In general, the offshore drilling industry has long accepted the concept that subsea accumulators are required for offshore BOP control systems in order to satisfy certain industry standards and regulations. However, the actual energy derived from subsea accumulators may fall short of the perceived benefits. Moreover, in some instances subsea accumulators may not be necessary, provided an appropriately sized rigid conduit line on the marine riser is utilized.

In the early days of offshore drilling, the industry relied solely on the energy stored in accumulators located subsea to, in part, speed the response times of the BOP. BOP control systems of this period typically utilized a one-inch inside diameter hose that transported hydraulic energy from the surface to the BOP stack functions subsea. The head loss due to friction from this relatively small hose over long distances was significant, resulting in BOP response times that were deemed too slow by the industry. As such, accumulators were mounted directly to the BOP stack to provide a shorter hydraulic conduit, thereby reducing head loss and response time. However, current research indicates that the benefit of these accumulators deteriorates rapidly with increasing water depths. Also, research suggests that utilizing a properly sized rigid conduit line to supply hydraulic energy to the BOP stack can provide acceptable control system response times without the use of subsea accumulators.

This paper analyzes the effects of water depth and other variables on the available energy in subsea accumulators. Also, it analyzes the available energy through BOP control system supply lines of various sizes. The paper concludes with recommendations on how to best maximize the required energy to operate subsea BOP stacks.
Results of the SPE Applied Technology Workshop ‘Off Well Site Decision Making’
Authors: Womer Keith , Kaminski Dean , Hansen Olav , Kirkman Matthew , Curry David
Published: December 2007

Communications technology has enabled drilling rigs to be connected in real time with off well site personnel. This powerful technology offers the opportunity for tremendous productivity and safety gains. However, if misapplied or abused, it could instead result in a disruption or breakdown of the rig's operational decision-making structure. The consequent loss of the sense of local ownership at the rig site could be disastrous in both a material and a human dimension.

This paper will present the results of an SPE Applied Technology Workshop held in April, 2002 designed to study these issues. At the workshop, real-world case studies and roundtable discussions were presented. Rather than just merely re-presenting the studies individually, this paper will also focus on presenting common themes arising from the studies, with references to specific cases as examples. Themes to be presented are: past history with this technology and lessons learned; the spectrum of off well site decision making implementations today – similarities, differences and critical success factors; people issues; the importance of data security and data standards; and the implications of this technology for health, safety and environmental issues.

Despite the diversity of the case studies, it is somewhat surprising that there were several common critical success factors identified by all participants to make the next generation of "off well site decision" implementations effective. The paper concludes by clearly identifying these factors and explaining why the overall outlook of the participants was decidedly optimistic.
Real Time Operations Centers; The People Aspects of Drilling Decision Making
Authors: Ursem Leendert-Jan , Williams Jevon H. , Pellerin Nicholas M. , Kaminski Dean H.
Published: December 2007

This paper will demonstrate how Shell and Halliburton-Sperry-Sun have implemented a world Class Real Time Operations Center (RTOC) using a holistic approach focused around people's needs while using the latest enabling technology. Although all the technology is available today to make the best decisions and to apply all the learning's of the past, the effectiveness of such a system is greatly linked to the behaviors of the people in the organization. Clearly addressing the people issues, is the largest step towards success for operational excellence, including safety. This paper will address five areas where people issues were taken into account.
Nakhchivan Drilling - Operational Success in a Challenging Environment
Authors: Jorden J. D. , Sandlin C. W.
Published: December 2007

Drilling in the Azerbaijan sector of Caspian Sea is very challenging and numerous drilling hazards must be overcome to successfully evaluate all exploration objectives. These challenges include numerous shallow hazards, complex pressure regimes, low fracture gradient, highly charged shallow water sands, reservoir sands that exhibit a pressure regression and the need to drill very deep to evaluate the geologic objectives.

A comprehensive well plan was developed to address these drilling challenges and hazards. The well plan had to address a rapidly increasing pore pressure relative to the fracture gradient and had to honor the resultant narrow drilling mud weight window. The plan called for setting 7 casing strings to allow drilling to the target depth. The plan also incorporated the first use of a "Big Bore" subsea wellhead system in the Caspian to accommodate these multiple casing strings.

The Nakhchivan #1 well was safely drilled to an Azerbaijan offshore depth record of 6746 m in 185 days. All exploration objectives were extensively evaluated and the well abandoned. Non-productive time was minimized though flawless execution of the well plan.

This paper will describe potential surface and subsurface hazards in the region, the well plan that was developed to mitigate these hazards and summarize the operations that led to the drilling successes.
Drilling Environmentally Friendly Satellite Field Wells in the Tundra of the Timan Pechora Region of Russia
Authors: Kukhtyak Zinovy , Perovsky Alexander , Sekerenova Svetlana
Published: December 2007

Polar Lights Company, a limited liability company formed by Conoco and Arkhangelskgeologia in January 1992 (later joined by "Rosneft"), stands out among petroleum ventures involving western companies in Russia today. Its Ardalin field development project in the Russian north, which produced first oil in August 1994, represents the single largest investment from the West in Russia's petroleum industry. The Polar Lights' license area is located in the Nenets Autonomous Area in the Timan Pechora region, about 125 kilometers south of the Barents Sea, above the Arctic Circle and west of the Ural Mountains.

Ardalin's complex consists of the main Ardalin field and 3 satellite fields. In 1997 the Company decided to commence satellite field development, utilizing an upgraded Russian drilling rig (Uralmash 3D-86) to meet the goal. The task was set forth to modularize the drilling rig such that the rig could be mobilized, the satellite well drilled and completed and the rig demobilized back to the Ardalin facility in one winter season, utilizing only ice pads with a minimum footprint and meeting all environmental requirements. By meeting this requirement (the elimination of gravel pads and their associated cost) the cost to mobilize and demobilize could be reduced and the environmental impact could be minimized such that following the spring thaw, the tundra's surface would be left undisturbed.

The modular, upgraded Russian drilling rig can be skidded from site to site (between the fields, up to 30 kilometers) and rigged up, the wells drilled and completed and the rig demobilized back to Ardalin in one winter season.

At the present time, the Polar Lights Company has drilled four satellite wells from ice pads in one winter season leaving the tundra's surface undisturbed and at a substatial cost benefit to the company.
Real-Time BHA Bending Information Reduces Risk when Drilling Hard Interbedded Formations
Authors: Hood J. , Hovden J. , Heisig G. , Ernesti K. D. , Knipper A.
Published: December 2007

Exploiting the Troll reservoir in the Norwegian North Sea requires horizontal drilling through relatively loose sandstone and local hard calcite-cemented zones. Depending on the orientation of the calcite interval, and the drilling parameters when entering or exiting the calcite interval, the bit can be forced aside to create a potentially severe local dogleg. High local doglegs introduce significant stresses into the drilling system that can rapidly accelerate fatigue of the BHA components and connections. Until recently, the driller could only identify local doglegs in the vertical plane when a rapid change of a near-bit inclination measurement was reported to the surface. No means were available for detecting azimuthal doglegs in the horizontal plane.

A new downhole dynamics tool, positioned above the rotary steerable system, is capable of measuring the bending moments in the BHA generated by side forces at the bit. If transmitted to the surface while drilling, the BHA bending information allows early detection and quantification of local doglegs independent of their orientation.

The paper explains the details of the bending moment measurement and the bending response of the BHA to local doglegs. Several field examples demonstrate the sensitivity of the measurement and the remedial actions initiated in response to the downhole BHA bending information. In one case drilling was stopped earlier than planned due to the detection of an extremely severe local dogleg, and a potentially catastrophic failure close to TD was avoided.
Application of Amphoteric Cellulose Ethers in Drilling Fluids
Authors: Warren Brent , van der Horst Peter , Stewart Wayne
Published: December 2007

Anionically charged cellulosic ethers have been used for many years in water-based drilling fluids. While the anionic charge imparts a benefit in the filter-cake properties of bentonite containing drilling fluids, this same charge deflocculates (thins) the viscosifying ability of this same bentonite. As a result, additional bentonite is often required in the drilling fluid to maintain an adequate rheological profile. Also, it is well known that cations are viscosity enhancers to bentonite drilling fluids by virtue of the flocculation effect of the cation. This has been used for many years in the potassium chloride (and similar salts) based drilling fluids.

Amphoteric Cellulose Ethers represent a new class of drilling fluid additives which combine an anionic and cationic charge onto the same cellulose backbone. The result is a drilling fluid additive having both desirable filter-cake enhancement and partial flocculation properties. Discussion will include the effects of degree of substitution for the anionic and cationic species, as well as the influence of molecular weight on the properties of the Amphoteric Cellulose Ethers.
Deployment, Monitoring and Optimisation of a Combined Scale/Corrosion Inhibitor within a Subsea Facility in the North Sea Basin
Authors: Jordan M. M. , Archibald I. , Donaldson L. , Stevens K. , Kemp S.
Published: December 2007

This paper presents field results and lessons learned from a North Sea field where a combined scale and corrosion inhibitor has been applied using a single formulation to control both the deposition of scale and associated corrosion. The Galley field is a subsea development within the UK sector of the North Sea. The use of a single product has facilitated a reduction in the number of umbilical lines to be used to provide flow assurance on the subsea flow lines and process of this facility.

The paper outlines the problems encountered when the initial formulation was deployed in the field and the steps taken to develop and monitor an improved formulation. Problems that can affect product application in a subsea environment, including deposition of suspended solids within the chemical, hydrate formation, incompatibility of the chemicals with umbilical material and produced fluid, will all be addressed. The laboratory methods used to select the product along with measurement methods used in the field are also discussed. The validation of the laboratory selection methods in the field required the development of a monitoring program to establish base line control and to assess the degree of protection from scale deposition and corrosion across the process.

The changing physical conditions within the flow lines and across the topside process will be described, as well as the changes in brine chemistry within the field, as injection water breakthrough occurred. The use of novel real time monitoring, as well as water chemistry tracking and analysis of suspended solids within the produced fluids across the process will prove vital to the understanding of the efficiency of flow assurance within the processes was and how treatment rates and products could be optimised.

This paper will outline in detail the particular issues associated with chemical injection to a subsea facility, many of which are currently being developed in the Gulf of Mexico and is a good example of lessons learned and sharing of best practice from another oil basin.
Preventing Erosion and Erosion Corrosion Using Specialty Chemicals
Authors: Ramachandran S. , Bartrip K. A. , Menendez C. , Coscio S.
Published: December 2007

In the current paper the ability of corrosion inhibitors to retard erosion corrosion in both purely erosive environments and environments with erosion corrosion are studied. The study uses measurements based on weight loss. The method of application of the inhibitor is studied by using a specified concentration of inhibitor in the experiment, filming the metal coupon or by using sand that has been exposed to a specified concentration of inhibitor. For the experiments that are done in a purely erosive environment, extrapolation of the laboratory results is done using an equation developed in previous work.1 The extrapolation indicates that using inhibitors in erosive environments can allow producers to safely transport more fluid or gas through an existing pipeline system.