Rig Floor Research Articles

Top Drive Casing Running: Challenges and Solutions

Abstract Opportunities to improve rig floor safety, reduce risks and reduce costs have motivated operators to utilize the top drive for casing running operations. Simple and easy approaches for applying make-up torque and hoisting loads to the casing string have been used with some success, but in some applications performing these functions safely, economically and without connection damage has not been trivial. Operational logistics, management of loads that cause casing thread damage and prevention of pipe body damage are examples of challenges requiring sound technical solutions. Pipe handling logistics, including engagement of the casing grip, must be executed efficiently without damaging casing threads or sealing surfaces. Similarly, bending loads resulting from rig misalignment or casing curvature can initiate thread damage if uncertainties remain unmanaged. Finally, local cold working of pipe body material increases stress cracking susceptibility, particularly on inner surfaces, and may reduce casing string reliability. Successful use of casing running technology depends on selecting a system that meets the technical requirements of the application. A sound understanding of casing thread make-up, drilling rig operations and the interaction between the two enables critical evaluation of emerging technologies and reduces the risk of commercial failure. This paper presents the background behind such evaluation and discusses a range of technologies in the context of that background. Introduction A desire to improve rig floor safety and eliminate unnecessary expenses has motivated oilfield operators to utilize the top drive for casing running operations. Applying make-up torque and hoisting the casing string can be accomplished quite easily, but performing these functions safely, economically and without damaging the casing body or connection threads and seals is not a trivial task. Several top drive casing running systems are commercially available, but consistently successful deployment requires that users carefully match technology with applications. Technical challenges are described here and solutions are characterized in an application- specific context. Successful exploitation of this emerging technology will occur more reliably with an understanding of the relationships between pipe, casing threads, running equipment and drilling rig operations. The simplest way to transfer torsion and axial load from the top drive quill to the casing is with a crossover, commonly referred to as a nubbin or make-up quill, from the top drive to the casing thread. This approach is widely used in western Canadian shallow hole applications, but fails to capture the full safety and economic benefit available through top drive casing running systems that engagethe pipe body rather than the casing threads(1). Specific top drive casing running tools are used in a broad range of applications. Success has been reported for casing runs in:highly deviated Gulf of Mexico wells(2);river crossings(2);onshore horizontal wells(2);desert wells(3); and,the North Sea(4).Compelling business cases for adopting top drive casing running systems have been published previously(1–4) and the subject will be treated here at a summary level only. The positive economic impact of using top drive casing running systems is evident in three areas.

Record ERD Well Drilled From a Floating Installation

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98945, "World-Record ERD Well Drilled From a Floating Installation in the North Sea," by A. Hjelle, SPE, T.G. Teige, SPE, K. Rolfsen, K.J. Hanken, SPE, and S. Hernes, SPE, Statoil, and Y. Huelvan, Schlumberger, prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21–23 February. Well 34/8-A-6 AHT2 was drilled from the Visund field floating production and drilling unit (FPDU) in the North Sea with initial production in October 2005. The well was drilled to 9082 m measured depth (MD) and has an along-hole depth of 7593 m. Introduction The Visund oil/gas field is 150 km offshore the west coast of Norway in a water depth of 335 m. The field was discovered in 1986, with first production in 1999. The depth of the main reservoir is 2900 to 3000 m true vertical depth (TVD), with a maximum pore pressure of 434 bar. The field is 24 km long and 4 km wide. With this field shape, extended-reach-drilling (ERD) wells drilled both to the north and to the south will increase drainage area and thereby the total recovery from the field. The Visund FPDU is centrally located over the field. The Visund North satellites consist of two wells tied back to the FPDU with a 9-km-long subsea pipeline. In the early preplanning phase, the subject well was planned as a separate subsea development, drilled by a separate semisubmersible rig. A new technical and economical study showed that this well could be drilled more economically from the existing Visund FPDU, through existing subsea systems. Fig. 1 shows the well profile. Planning Phase The planning phase of this well was performed by use of the continuous-improvements model (Fig. 2). The first plan recommended drilling for a separate subsea-development well. After gaining experience, it was decided that the well could be drilled from the Visund FPDU. The drilling plan was completed together with a separate risk document covering critical events that could be identified before drilling the well. This risk identification process was performed in a workshop together with the service companies and the drilling-contractor personnel working on the Visund field. The detailed rig procedures that were to be used on the rig floor also were prepared onshore in the same type of workshops. This proved to be a good way of building a committed team and identifying risks and parallel activities that could be prepared before the operation. Peer assist and review were performed on this well to ensure that relevant experiences were included in the planning phase. After the well was completed, a final well meeting was held with the involved service companies ensuring that relevant experiences were recorded for the next well.

The Continuous-Circulation System: An Advance in Constant-Pressure Drilling

Summary In late July 2003, for the first time since rotary drilling was introduced, a section of hole was drilled without interrupting circulation while new joints of drillpipe were added to the drillstring. This was made possible by the use of the continuous-circulation system (CCS), developed over the previous 3 years by a joint industry project (JIP) that was managed by Maris Intl. and funded by six major oil companies (Shell U.K., BP, Statoil, BG, Total, and Eni),Coupler Development Ltd., and Varco, and supported by the U.K.'s Industry Technology Facilitator. The field trial of the CCS was carried out on a land well being drilled in Oklahoma, U.S.A. Its success marked the end of the JIP and the commencement of commercial development of the system. The CCS is a new and enabling technology; the potential benefits of which include the following: Elimination of negative and positive pressure surges when stopping and starting circulation to make a connection. No rig downtime to circulate out cuttings to clear the bottomhole assembly before making a connection. Improved drilling-fluid management. Elimination of kicks on connections. Improved control of equivalent circulation density (ECD). Reduced total connection time (TCT). Reduced chance of stuck pipe during a connection. No downtime in high-pressure/high-temperature (HP/HT) wells to circulate out connection gas. Reduced wellbore "breathing" or "ballooning." Improved safety around the rig floor. Potential applications of the system include the following: Extended-reach drilling (ERD) and horizontal wells. HP/HT wells. Near or underbalance wells. Deepwater wells. The CCS is also a potential-enabling technology in achieving the "one-tripwell."1 The concept was presented in a paper by inventor L. Ayling at the Offshore Technology Conference, May 2002.2

Real-Time Specific Energy Monitoring Enhances the Understanding of When To Pull Worn PDC Bits

Summary Knowing when to change dulled bits can significantly reduce costs, which can be particularly important in high-cost environments. However, current techniques are based more on speculation and hope rather than science. The concept developed to dramatically improve this inefficient decision process involved measuring the mechanical energy input at the drill rig floor, calculating the drilling specific energy (SE), checking the current formation type with real-time downhole gamma ray (GR) readings, comparing the SE with the benchmark new-bit SE, and then using these values to assess the bit's "dull" state. This method has been proven to work in synthetic-based mud systems in which balling does not mask the bit's dull condition. It was imperative that the operator proved that this process worked in water-based drilling fluids that had replaced earlier synthetic muds because of environmental concerns, cost, and improved performance in water-based mud (WBM). Recently, the operator established that this process worked in water-based mud systems treated with antiballing chemicals. The case studies in which this methodology was developed are presented and discussed.

POST‐DRILLING ANALYSIS OF THE NORTH FALKLAND BASIN—PART 2: PETROLEUM SYSTEM AND FUTURE PROSPECTS

Six wells were drilled in the North Falkland Basin in 1998. Five of these wells recorded oil shows, and up to 32% gas was also recorded in mud returns to the rig floor. However, none of the wells encountered commercially viable petroleum accumulations.The syn‐rift and early post‐rift intervals contain thick, lacustrine claystones with oil source potential as indicated by TOC values up to 7.5% and Rock‐Eva1 S2 values of up to 102 kg HC per tonne of rock. These source rocks were immature or only marginally mature in five of the wells but had attained maturity in one of them. Modelling suggests that the main source interval may well be within the peak oil generation window in deeper, undrilled parts of the basin. Calculations of the amount of oil expelled range up to 60 billion barrels.Most of the wells tested a closely‐related set of plays in large structures asSociated with a sandstone interval near the top of the late syn‐rifi to early post‐rij? source‐rock succession. Post‐drilling geological modelling of the basin suggests that oil is unlikely to have migrated into this sandstone play at the localities tested, and that the wells consequently failed largely due to a lack of charge. Howevel; the play maintains exploration potential elsewhere. Other plays, particularly those stratigraphically asSociated with the base rather than the top of the source rock, may have a higher chance of exploration success.

New Disclosures in Predicting Stand Pipe Pressures While Drilling

For the purpose of the present paper the analytical formulations of Herschel and Bulkley rheological model including the most relevant expressions of pressure drops, valid both for circular and annular sections, are applied in order to determine the three characteristic parameters of a known drilling fluid, having yield pseudoplastic behaviour, and flowing in the drilling hydraulic circuit, starting from field circulation tests. As it is well known, a typical standard drilling hydraulic circuit consists of the surface circuit (stand pipe, rotary hose, swivel and kelly, the circular section (inside the drill string with variable diameters), the bit and the annular section (the gap between the borehole wall or casing and the drill string). In this circuit the drilling mud enters the drill pipe, comes out from the bit, flows up through the annulus up to the surface, where (after a short time for cleaning) it is put back in the circuit. The parameters to be inspected are the yield point t0, the consistency index k, the flow behaviour index n. By means of at least 3 flow tests at a certain drilling depth, with the bit off bottom, the pump rates and the corresponding stand pipe pressures are recorded. The obtained N couple of values of stand pipe pressure and pump rate, the geometry of the hydraulic circuit and the fluid density are the input data for a numerical procedure to determine the three parameters of the considered drilling fluid. In this way, using this numerical process, a nonlinear system of N equations (with N≥3) having 3 unknowns (the three parameters of the fluid: n, k and t0) is solved determining the Herschel and Bulkley rheological parameters. This procedure inspects the most probable solution for each tentative value of the flow behaviour index np, considering the infinite couples of t0 and k satisfying the input value of the stand pipe pressure. Through the computation of the mean square deviation for each of the tentative values of np , the solution term of the nonlinear system of N equations can be obtained. The computed results are compared to the ones obtained using the readings on the same drilling mud performed on Fann VG 35 viscometer. Not always the rheological term outcoming from the viscometer data exactly fits the equivalent rheological term found by considering the drilling well as a viscometer. Computed SPP data using the equivalent rheological term and the rheological parameters from viscometer readings, using diferent rheological models such a s Bingham, Ostwald and de Waele and Herschel and Bulkley, are compared to field stand pipe pressure data. It can be seen that the overall average error between measured and computed SPP (using the Herschel and Bulkley equivalent term) has drastically reduced to very small values, while the com- puted SPP using viscometer readings with most of the rheological models today used could lead to large errors, thus misleading an accurate evaluation of the SPP on the rig floor site. This procedure shows to be useful even to carefully evaluate the annular pressure drop and the corresponding ECD, in order to have the maximum allowable pump rates without fracturing the crossed formations. Additionally, it could be used to monitor the SPP behaviour for potential problems in the hydraulic circuit, such a s wash out events, plugged nozzles, and also in the case of gas kicks in the well. If applied to different dril- ling depths, the method can usefully inspect the influence of pressure and temperature exis- ting in the well upon the rheology of the mud. This particular characterization is going to be inspected in the forthcoming research stages, which have already been designed to date.

Data Model for Drilling Information and its Application

As computing technology has evolved, so have the demands placed by the user community on the functions it provides. The expectations of software used in drilling operations are changing from a convenient way of producing the daily drilling report, to acquiring drilling data for use in engineering analysis programs. This data is expected to provide insight into an increasing array of complicated engineering operations questions. There are a number of commercial morning reporting systems in use throughout the industry. However, after collecting many years worth of drilling data, the engineer is finding that their morning reporting system cannot easily provide the answers to some very basic questions. Many providers of drilling information systems have built their applications founded on daily wellsite operations, using the latest Graphical User Interfaces (GUIs) to ensure their case of use. The data model is usually an afterthought, and is generally time rather than activity based. In some cases, the data model is used as a tool to further the system`s {open_quotes}user-friendliness{close_quotes}. This robs the application of its versatility in performing even some of the most fundamental analysis of the data. To date, neither POSC (Petrotechnical Open Systems Corporation) nor the PPDM (Public Petroleum Data Model)more » have initiated studies to develop a drilling data model. The authors will present a data model that was used as a basis for Shell Canada`s (SCan) Drilling Information System. The provision of a sound data model, that accurately reflects the fundamental data used by drilling (or other operations), is paramount to the success of any information system. Without it, the utilization of engineering operations analysis tools for optimization would be extremely difficult.« less

Coiled-Tubing Applications for Blowout-Control Operations

Coiled-tubing drilling is now being used in various operations. Its complete field of applications is not currently established. Coiled tubing used for well control while drilling is a new field where its limits are being explored. This paper provides guidelines on topics to be considered in determining the applicability of coiled tubing for well-control problems. The information provided is based on recent field experiences with several well-control problems when drilling vent and relief wells. In some cases, coiled-tubing drilling capabilities, by necessity, were significantly extended beyond levels the industry considered to be upper limits. Well control cannot always be handled by coiled tubing. It is a special-application tool that can handle many situations and is, in some cases, clearly the optimum choice for the application. This paper presents guidelines for selecting coiled tubing for each application and discusses economics. It also describes coiled-tubing operations for regaining control of blowout wells in certain situations and gives technical requirements for planning and executing these types of jobs. Case histories where coiled-tubing units (CTU`s) have been used to regain control of drilling and producing wells are provided for illustration.

Detailed Subsurface Descriptions Drive Record Breaking Wells in the Deep Water Gulf of Mexico: ABSTRACT

Increased well productivity is motivating development teams to successfully complete record breaking wells. Advances in subsurface description are leveraging with breakthroughs in drilling and completion technology to achieve new levels of financial performance. Gulf of Mexico industry and company records have recently been set in extended reach drilling, horizontal drilling, curvilinear completions, and frac-packed high angle completions. These advanced well designs are establishing new production records in the deep water Gulf of Mexico. Improvements in 3D seismic imaging, geologic depositional models, and reservoir pressure predictions are enhancing the subsurface model such that significant productivity benefits are achieved by targeting completions in specific geometries. Advances in directional drilling accuracy and the utilization of synthetic oil-base muds are assuring that wells are placed precisely on target. In the BP operated Pompano Field horizontal wells have been placed down turbidite channel axes, high angle wells are used to connect separate reservoir compartments, extended reach wells have been steered away from over-pressured sections identified from seismic, and a multi-lateral completion is next on the drilling schedule. Multi-disciplinary innovation and focused teamwork is also changing behavioral working styles. It is now accepted that the [open quote]teams[close quotes] consist of geoscientists, engineers, and offshore drilling hands.more » Well planning takes place both on the rig floor and in the office. The payoff for further integration is higher profits, lower risk, and a safer working environment.« less

Loads on Drillpipe During Jarring Operations

Summary Jarring implies heavy loads on the drillstring. The highest load on the drillpipe before jarring is at the rig floor. This paper discusses loads on drillpipe before, under, and after jarring. We show that for most situations, the shock wave from the jar impact does not imply additional load on the drillpipe compared with static load. The theoretical results are confirmed by measurements of a jarring operation with stuck point at ≈ 1200 m measured depth. Loads on the drillpipe can be a limiting factor in jarring operations because fear of possible additional loads from jarring dynamics may restrict the trip force (overpull) on the jar. Our main conclusion is that dynamic jar forces do not give additional loads on drillpipe. This information can be used to set an optimal trip force on the jar.

Torque and Drag-Two Factors in Extended-Reach Drilling

This paper addresses the various aspects of torque and drag problems encountered in drilling extended-reach wells. It discusses how to use torque and drag calculations and measurements to plan long-reach well profiles, to execute drilling operations that minimize torque and drag effects, to monitor hole cleaning, and to plan jarring operations.

Analysis of the Inflow and Pressure Buildup Under Impending Blowout Conditions

In this study a technique is provided for determining formation pore pressure and flow properties based upon analysis of shut-in drill pipe pressure. Both radial and spherical transient flow of slightly compressible fluid are considered. Solutions are provided in dimensionless forms. A newly developed concept of effective (equivalent) flowing rate and time is applied to replace the unknown variable flow rate which takes place prior to shutting-in the well. Two numerical examples show how to utilize the information on pit gain, approximate flow-in time and the shut-in drill pipe pressure to determine formation fluid pressure. Fluid mobility (spherical flow) and formation transmissibility (radial flow) can also be determined from knowledge of shut-in drill pipe pressure as a function of time. Application of the proposed method is simple, and therefore, useful on the rig floor.

Performance Auditing System for Drilling Units and Platforms

Summary For a number of years, the drilling industry has measured a negative aspect, "lost time accidents" (LTA), to indicate the safety performance of a drilling unit or performance of a drilling unit or platform. The performance auditing platform. The performance auditing system presented here is a positive approach to measuring the safety performance of a drilling unit or performance of a drilling unit or platform. The system gives the rig owner platform. The system gives the rig owner indicators to help steer and improve safety management and an attractive incentive for crew to contribute to a safe drilling unit or platform. Introduction Although safety and health always have had considerable attention within our organization, the number of LTA's became unacceptably high in 1984. At that time, it was decided to restructure safety management within the company. A qualified nautical officer dedicated his time to set up a safety management system. In this phase, safety policies and procedures were written for the operations procedures were written for the operations manual. The condition of the safety hardware on the drilling units was further improved. The available accident reports were reviewed, and the results showed that most accidents occurred on the rig floor. On the basis of this evaluation, management decided to install an automatic pipe-handling system for making up and breaking out tubulars on all drilling units. These steps (new procedures and policies, better hardware, and drill-floor mechanization) resulted in a drastic improvement in the accident frequency rate. Also, considerable funds and manpower were made available for safety improvement drives and programs aimed to ensure the safety of the programs aimed to ensure the safety of the employees in their work environment. Safety programs covered a wide range of activities, such as on-the-job supervision, safety introductions for newcomers, in-house training courses on safe maintenance and operation of drilling equipment, regular safety hardware inspections, procedures to handle chemicals safely, anonymous near-miss reporting, accident investigation and analysis, emergency contingency plans, and engineering process control. Periods without LTA's were rewarded with cash or gifts. A downward trend in the frequency rate continued until 1988, alter which the number of LTA's increased. The cause of this increase was not immediately identified. More accidents occurred worldwide, as reflected in an increase in the frequency rate. New initiatives were launched in 1989 to curb this trend. A separate department put even more effort into safety and created a positive image of safety progress by means positive image of safety progress by means of the performance auditing system.

Improved Coiled-Tubing Squeeze-Cementing Techniques at Prudhoe Bay

Summary. This paper presents major changes in coiled-tubing squeeze-cementing techniques used in the Prudhoe Bay Unit Western Operating Area (PBUWOA). Changes include introduction of a polymer diluent to replace borax contamination, increased differential pressures placed on squeeze and coil, reduced cement volumes, and incorporation of an inflow test and resqueeze procedure. These changes resulted in increased squeeze effectiveness by reducing equipment and engineering time requirements and by shortening well shut-in time after the workover. Introduction Coiled tubing was introduced to the Alaskan North Slope because it is fast, mobile, relatively inexpensive, and well suited to subzero conditions. It is used extensively for a variety of purposes, including logging high-angle and horizontal wells, perforating, underreaming, cleaning out fill, squeeze cementing, and stimulating with acid. This paper focuses on squeeze cementing, also referred to as coiled-tubing unit (CTU) workovers. Techniques and data apply only to the PBUWOA. The primary objective of the original coiled-tubing squeeze-cement program, from late 1985 through mid-1988, was to extend plateau oil production. The anticipated decline point was delayed by working over wells that had the greatest potential for increasing oil rate and reducing excess gas. Reducing gas production from the worst offenders freed facility gas capacity to handle oil production from other wells with high producing GOR. These other high-GOR wells produced gas at rates greater than the acceptable field average, but not nearly as high as the wells with the highest priority for workovers. Freeing up facility gas capacity was then equivalent to bringing on shut-in oil wells. Coiled tubing is a continuous string of 1.5- or 1.75-in.-nominal-OD pipe wrapped around a reel and secured to a mobile control unit. Coil is threaded through an injector head (Fig. 1), pulled off the reel, and fed through well-control equipment (including pipe blind, shear and slip rams, and hydraulic control system) and into the well. Currently, about 10 CTU's are available for use on the North Slope, and BP Exploration (Alaska) has four on contract. Fig. 2 depicts a representative wellbore in the PBUWOA. It includes a 9 5/8-in. production casing set just above the Sag River formation and a 7-in. production liner set through 40 to 50 vertical ft of the Sag River formation and about 500 vertical ft of Ivishak formation, the primary productive interval in the field. Most of the wells are completed with a 9 5/8-in. packer with 4 1/2-in. tailpipe set immediately above the 7-in. liner top. The packer and tailpipe assembly are generally completed to the surface with 4 1/2- 51/2, or 7-in. tubing. Original CTU Squeeze Technique The original Prudhoe Bay Unit CTU squeeze technique was developed to reduce reservoir control costs compared with those of an arctic-rig workover. The CTU is mobile and requires less well preparation than an arctic rig. Arctic Conditions. The first technical issue resolved during development of the original program was year-round operating flexibility. Temperatures on the North Slope often dip below -40F and wind speeds reach 60 miles/hr during the winter. An individual on-site laboratory, manifold system, and tank farm were designed and constructed to be mobile and enclosed for heat. Air compressors are used to blow most soft lines dry, and a supply of methanol is kept on location to protect hard lines, coil, and the well, if necessary, from freezing. The CTU itself is well-suited to arctic conditions with an enclosed operating cab, no tubing joints to break or make up, and therefore no rig floor to heat. Removal of Excess Cement. The second major issue concerned removal of excess cement without drilling. In areas other than Alaska, the oil industry uses coiled tubing to squeeze cement into perforations or other liner breaches. In most cases, cement is cleaned out of the wellbore by moving in a rig and drilling out hard cement. Coil can be used to reverse out excess cement after a squeeze. However, special care must be taken with rates and pressures during the reverse-out because coil collapse is a major concern. Coiled tubing is thin-walled, flexible, and relatively fragile compared with jointed pipe. Because several coil collapses occurred early in the program, and published test data were lacking, differential pressures across the coil were limited to 1,500 psi until 1989. To avoid drilling and to reverse out cement within pressure guidelines for the coil and formation, a cement dilution and retardation fluid was developed. JPT P. 455^

An Ergonomics Perspective on Safety in the Oilfield

Safety analyses of drilling operations are often written from the perspectives of regulation, economics, industry structure, etc. The ergonomic perspective on safety emphasizes that equipment and operations should be designed in light of human capabilities and limitations. To demonstrate this approach a scenario analysis was performed on records for 134 safety incidents on oilwell drilling rigs. The characteristics of the most critical scenarios were then considered to determine the extent to which the ergonomics of environment, equipment, and work methods might have contributed. Ergonomic data was collected at four drilling sites, including a prototype semi-automated rig. From both ergonomic and safety perspectives, the work situation of operators on a conventional rig floor is most in need of remediation. Mechanical pipe handling would provide the most complete solution to this unpleasant and unsafe environment, its strenuous and over-extending tasks, and the risks inherent in putting people near heavy moving objects. Significant improvements can be made at the detail level and at minimum cost in some tasks. Improvement in other tasks requires basic conceptual changes in rig systems and architecture. To realize their potential, new rig concepts must be carefully and systematically designed, and ergonomics should be considered throughout their design.

Further Discussion of Application of Oil Muds

Abstract I would like to commend J.W. Bloemendal on a very good paper, "Discussion of Application of Oil Muds" (Oct. 1986 SPEDE, Page 395). On the basis of my 22 years' experience in drilling and well control, I would like to offer some of my field experience as related to oil-based muds. First, oil-based muds do have specific applications; however, the recent universal use of oil-based muds is without economic justification. I am familiar with some instances in which freshwater muds were arbitrarily replaced by salt and polymer systems without engineering justification. Because of costs and operational problems, some operators reverted to freshwater muds and realized tremendous savings, while others opted for oil muds to solve operational problems at a significant increase in costs. Some operators elected to use "nontoxic" oil muds at even greater costs. So now we are drilling with "Crisco"! As an experienced field engineer, I have witnessed the most severe and obvious cases of formation damage from the use of oil muds. These cases occurred in deep, high-pressure, low-permeability productive intervals. It is my opinion that the damage, which may not be reversible, is caused by the presence of the surface-active agents in the oil mud that permit the invert emulsion and the oil wetting of bentonite and barite. This change in surface tension could significantly affect the relative permeabilities and thus cause formation damage. I have also been involved in well-control operations and training on a worldwide basis for more than 20 years. Well-control problems are complicated in the presence of oil muds and have resulted in disasters and dangers. In one instance, a well took a kick with an oil-based mud in the hole. After the well had been physically brought under control, the oil mud on the rig floor caught fire and burned through the rotary hose. The well blew out through the drillstring and destroyed the rig.

Minimum Area Rig Concept Update: H and P 101 Modifications and First Infield Move

Summary. The minimum area rig concept (MARC) is a cost-effective alternative to the typical self-contained platform rig (SCPR). Helmerich and Payne (H and P) built the first MARC rig, H and P 101, to drill and to work over wells up to 16,000 ft [4877 m] measured depth. This rig began operation in May 1983 in the Gulf of Mexico at Arco Oil and Gas Co.'s South Pass Block 61 field and has undergone one infield move. Since the rig's initial mobilization, several rig modifications have been added to increase storage area, to promote safety, to provide a more efficient drilling/workover rig, and to reduce overall move time. This paper describes the modifications and recaps the rig's first move. This will provide further insight into the MARC rig and show the benefits of the MARC design in relation to a move. Introduction H and P Rig 101 was designed, contracted, and built to work in the South Pass 61 field. The rig was mobilized initially in May 1983 and has proved to be the most efficient offshore drilling/workover rig in service in our Southeastern Dist. A savings of $1.4 million/yr over an SCPR has been realized as a result of lower day rate (lower initial investment) and mobilization/demobilization costs. The MARC design was needed in the operator's offshore environment to facilitate drilling and workover operations on producing platforms. All the platforms in the South Pass Block 61 field have production equipment on the drill deck (i.e., quarters and compressors), leaving approximately 75 % of the deck for a drilling/workover rig. Consequently, a rig was needed that would fit in the limited space but would still have the capabilities to drill and to work over up to 16,000-ft [4877-m] directional wells. (See Figs. 1 and 2 for original rig layout.) Economics was also an important criterion considered in the MARC design. The MARC rig design was planned to service the operator's platforms easily, yet eliminate an expensive derrick barge for each move. As a result, the "leapfrog" crane concept was used, whereby the crane that offloads the rig from the barges to the platform serves as the rig crane through the next move. H and P Rig 101 was mobilized initially on South Pass Block 60 Platform D, performed 12 workovers, and drilled eight wells. Modifications to the rig have been made, and the rig has moved to other platforms. This paper documents the modifications and the first move. Rig Modifications The deficiencies with the original MARC design evolved around the limited available space and resultant space use. Modifications were proposed to add badly needed storage area and to improve the overall efficiency of drilling, workover, and moving operations. We contracted IMI Engineering, the firm that originally designed the rig, to perform a third-party engineering evaluation of what improvements could be made without exceeding existing load limits. We requested that IMI submit a turnkey bid for construction and supervision through installation of the approved modifications. Construction-grade drawings were made, and after a final meeting, work on the modifications began. The following is a description of each modification. Drawworks/Wireline Shed. One of the most apparent areas in need of improvement was a permanent position for an electrical wireline unit. The skid-mounted units being used were costing the rig up- and downtime, and damages were occurring during transport and handling. Also, covered storage was limited on the rig. As a result, a drawworks/wireline shed was designed to fit on the back porch of the rig floor. This shed incorporated a permanent position for an electrical wireline unit, a covered storage area in a place that was previously open to the weather, and a mast stand that is needed to rig up or down the derrick. The shed was welded to the back porch. so it did not add a lift during moves. The wireline unit was installed on top of the shed and is out of the way during normal operations (Fig. 3). Besides supplying a covered storage area for small tools, the shed protects the previously open rig floor from weather. Mud Logger Floor. The permanent mud-logging unit consumed too much space in its original location, the "hole" on the drill deck between the pipe rack and rig structures. It was left rigged up when possible, regardless of whether completion or workover operations were in progress. This was taking up valuable equipment storage space, however, especially during gravel packs, and was unsafe (approximately 50% of the crane lifts passed over the unit). JPT P. 340^

The Minimum Space Platform Rig (MSPR)-Its Adaptability to Onshore Drilling Applications

Summary The Minimum Space Platform Rig (MSPR TM) concept, pioneered by Pool Offshore Co. in 1969, has gained wide acceptance in the Gulf of Mexico, offshore California, and in international waters for its ability to operate within restricted space limitations on offshore drilling and production platforms. The same design features that make the concept so adaptable to a wide range of platform deck configurations have proved operationally and economically advantageous for drilling onshore, over multiwell cellars, and on such restricted locations as townsite lots and on hillsides in rugged terrain. Introduction In the early 1890's, the first wells drilled offshore in the U.S. were drilled from wooden piers, some up to 1,200 ft [365.76 m] long, in relatively shallow waters off Summerland, CA, near Santa Barbara (Fig. 1). The rigs used to drill off these piers were identical to those used on land. Although the method was unique at that time, the technique never proved economically viable. Nearly a hundred years later, in the 1980's, we saw a reversal of this situation when rigs designed specifically for offshore-platform development drilling were first used onshore California. In this case, however, the technique has proved operationally and economically successful because space limitations dictated the use of some type of unconventional rig configuration. This paper covers the design features of the MSPR rig concept and the advantages such features provide for onshore, limited-space drilling applications. Examples of several onshore drilling applications are given. MSPR Design Features The MSPR design was conceived with the intent to develop offshore-platform drilling or workover rigs that would have the following advantages (Fig. 2).They would provide a minimal footprint on the platform deck yet have the power and hookload capabilities to compete with conventional platform rigs at comparable well depths.They would be capable of "bootstrap" fig-up and rig-down.They would have the capability to alter the rig configuration to meet a wide range of platform designs and deck-space limitations.They would have the ability to skid, fully rigged, from well slot to well slot and center the rig package over each slot. Fig. 3 is an explosion schematic showing the component design features of the basic MSPR rig system. The MSPR is designed to fit the standard skid beams on the platform deck. Jacking beams (or false capping beams) are superimposed over the platform skid beams. These beams contain jacking claw slots used in securing hydraulic skid jacks, which are used to move and to position the rig over the well slots. Next are the mud tanks, which serve a dual purpose. They not only make up the drilling fluid system and provide bulk liquid storage but also serve as the primary support, or substructure, for the rig package. A set of strongbacks is installed on top of the storage tank substructure. The strongbacks also serve a dual purpose: they form the foundation for the rig floor and pony structure for the crane and ar-e used for storage of diesel fuel and other fluids. The cantilevered pony structure serves as the base for a modular skidding crane that is used to erect the rig package components. Mounted above the strongbacks are the rig floor and pipe walk. The rig floor package contains the drawworks, rotary table, driller's console, and other rig floor equipment. Next is the mast base section, fitted with a wireline platform that is pinned to the rig floor for support. Once the mast base section is secured in place, additional mast sections are erected vertically from the base section in a telescoping manner. Finally, the mast crown section is raised, using the wireline and drawworks. These are the basic rig components. To complete the rig-up (Fig. 4), the traveling gear is strung up inside the mast, and all other components-such as pumps, engines, logging units, and bulk tanks-are installed on the platform deck or on pony structures. Another unique feature of the MSPR design is that modular quarters buildings, including a helicopter deck and pipe racks, are cantilevered off the platform using the cantilever capping beams for support (Fig. 5). As stated before, all rig components are erected on the platform using the platform crane initially and the modular skidding crane later. To rig down, the procedure is reversed. Although weather, platform design, and other factors can influence erection time, an MSPR has been erected in as few as 14 days under ideal conditions. JPT P. 1633^

Qualifying Drillstring Components for Deep Drilling

Summary Deep, hard, or directional drilling imposes extraordinary stresses on drillstring components. Because of theadditional economic risks of deep drilling, the inspection and acceptance of drillstring components should be based ontheir compliance with API and user standards. Inspection procedures that provide the highest probability of finding procedures that provide the highest probability of finding and eliminating unacceptable components should be used. Often, too much reliance is placed on a "report" or"certification" that the drill string components have been"inspected, "The operator assumes that because the material has been inspected, it is suitable for the intended service. This paper addresses three areas in which the above approach may lead to trouble.Widespread, established practices have resulted insome applicable API guidelines being unintentionally ignored by users and inspection companies.API standards for used drillpipe do not address someitems of concern to operators engaged in deep or critical drilling.Inspection companies frequently do not followsimple quality control steps that can markedly improve theresults of their work. Examples of shortcomings in current industry practicesare given. Corrective actions implemented by several companies in the last 12 to 18 months are also given. A hand-held calculator program that will aid in evaluating the wear limits on rotary shouldered connections isprovided in the Appendix. provided in the Appendix. Drillstring Failures Examples of drillstring failures are well documented inliterature. 1 Unfortunately, they are also all too familiarto most drilling engineers and operations managers fromfirsth and experience. Common in-service failures include the following.Fatigue cracks can be induced by cyclic loading inhigh-stress areas of connections and drillpipe tubes(Fig. 1).Washouts caused by leaking drilling mud can erodemetal and enlarge the leak (Fig. 2). Leaks may occur fora variety of reasons, but the most common causes are fatigue cracks, inadequate makeup torque, shoulder sealdamage, or excessive or improper refacing of the shoulders.Tensile breaks occur when the load-carrying capacityof a member is exceeded. This occurs most frequentlyin the tube body (Fig. 3) or in the pin of a connection.Torsional failures occur when the torque applied indrilling exceeds the capacity of a drillstring componentto resist torque. Fig. 4 is an example of a torsional failurein a drillpipe box. Drillpipe failures occur for a variety of reasons. Broadly speaking, these can be grouped into three categories. If a failure occurs eitherthe drill string was designedincorrectly-e.g., the weight and grade were inadequatefor the application;the drillstring was misused-e.g., connections were over torqued during rig floor makeup;ordefective components were accepted and runbecause of inadequate inspection, poor-quality inspection, or poor definition of the standards of acceptance. It has been our experience that persons responsible for drilling wells are much more familiar with the design and proper use of drill strings than they are with inspection proper use of drill strings than they are with inspection processes and acceptance standards for those strings. In processes and acceptance standards for those strings. In the hope of helping to correct this situation, the remainder of this paper addresses some problems and solutions inthe area of drillstring inspection. Drillstring Inspection There seems to be a pervasive attitude among drillingpeople that inspection is someone else's problem. Few oil people that inspection is someone else's problem. Few oil companies would write the following clause into theirday-rate drilling contract. The drilling contractor shall decide well location, well depth, directional program, mud program, logging program, casing and cementing program, and whether the well will be completed or abandoned. Contractor shall provide a report certifying that allthe above was done correctly. On the other hand, most companies do not hesitate todelegate the inspection and acceptance of their drillstring components to their contractor or inspection company. It is still common practice to accept an inspection "report"as proof that the components have been inspected. Frequently, when failures occur, the corrective measure maybe to change inspection companies and to repeat the cycle, without any technical involvement in the inspection process. Our message is that the operator can often process. Our message is that the operator can often substantially reduce his economic exposure to drillstring failuresby becoming involved in the inspection process. JPT P. 1511

An Experimental Study of Well Control Procedures for Deepwater Drilling Operations

Summary A research facility has been designed and constructed to model thewell-control flow geometry present on a floating drilling vessel operating in 3,000 ft [914 m] of water. The main feature of thisfacility is a highly instrumented 6,000-ft [1829-m] well equipped with a packer and triple parallel flow tube at 3,000 ft [914 m] tomodel a subsea blow out preventer (BOP) stack with connecting subseachoke and kill lines. Several types of experiments were conductedin which gas kicks were simulated by the injection of nitrogen intothe bottom of the well. Alternative procedures studied andevaluated included techniques to compensate for chokeline frictional pressure loss during pump startup and techniques forhandling rapid gas-zone elongation when the kick reaches theseafloor. It was found that the demands placed on a choke operator during well-control operations in deep water were not as severe asanticipated from computer simulator studies and could be managedwith existing equipment by an experienced choke operator. Introduction In the late 1940's, the search for oil and gas accumulations firstmoved offshore to the shallow marine environment. Since that time, drilling operations have been extended steadily across thecontinental shelf. More recently, developments in the technologyfor drilling from floating drilling vessels have allowed exploratory drilling beyond the limits of the continental shelf andinto the relatively deep water of the continental slopes. In 1974, the first well was drilled in water deeper than 2,000 ft [610 in].1 By 1979, the water depth record was extended to 4,876 ft [1486in] on a well drilled offshore Newfoundland. More recent exploration offthe U.S. east coast extended the water depth record to 6,848 ft[2087 m]. Future plans in the Natl. Science Foundation's Ocean MarginDrilling Program call for scientific ocean drilling during the nextdecade in water depths of 13,000 ft [3962 m]. Like many other aspects of drilling operations, the problemof blowout prevention increases in complexity for floating drillingvessels operating in deep water. Several special well-control problems stem from greatly reduced fracture gradients and the use problems stem from greatly reduced fracture gradients and the use of long subsea choke and kill lines. Fig. 1 shows the approximateeffect of water depth on fracture gradients, expressed in terms ofthe maximum mud density that can be, sustained during normal drillingoperations. 4 Note that the maximum mud density that can be used withcasing penetrating 3,500 ft [1067 m] into the sediments decreases fromabout 13.9 lbm/gal [1666 kg/m3] on land to about 10.7 lbm/gal [1282 kg/m3]in 4,500 ft [1372 m] of water, and to about 9.8 lbm/gal [1174 kg/m3] in13,000 ft [3962 m] of water. These lower fracture gradients resultprimarily because the open hole must support a column of drilling fluid primarily because the open hole must support a column of drilling fluid that extends far above the mudline to the rig floor. This additionalcolumn weight is only partially offset by the seawater. An additional contributing factor is the relatively low bulk density of unconsolidated shallow marine sediments. The required vertical subsea choke and kill lines extendingfrom the BOP stack at the seafloor have two detrimental aspects. One difficulty arises because of the increased circulating frictional pressure loss caused by the great length of these lines. This frictional pressure loss can cause a significant increase inthe pressures occurring in the wellbore. The combination of highcirculating pressure losses in the chokeline and low wellborefracture gradients reduces the tolerance for error by the chokeoperator. A second difficulty results from rapid changes in hydrostaticpressure in the vertical chokelines when circulating a gas kick. pressure in the vertical chokelines when circulating a gas kick. Hydrostatic pressure falls quickly when gas exits the large casingand displaces mud from the relatively small-diameter chokeline. To maintain the bottomhole pressure (BHP) constant, there must be acorresponding increase in surface choke pressure to make up forthis decrease in hydrostatic pressure. Choke operation becomesmuch more difficult during this period, as rapid changes in controlpressure are required. This difficulty tends to increase with well pressure are required. This difficulty tends to increase with well depth because choke manipulation is based on surface drill pipepressure whose unsteady-state readjustment time increases with well pressure whose unsteady-state readjustment time increases with well depth and gas-kick volume. Evaluations of anticipated well-control problems for a givenset of deepwater conditions are often conducted by computer studiesthat predict the pressure response of a well for variousalternative procedures being evaluated. These studies have raisedquestions about the severity of the control problem faced by the choke operator. JPT p. 1239