Rig Operations Research Articles

Innovation: Well Evaluation Innovation

President's column From the earliest drilling operations, the need for operators to see the penetrated formation was paramount, in their minds. They needed to distinguish not only the rock properties but also their content and deliverability. The first electrical well-logging operation took place in 1927 after many years of successful experiments with surface resistivity measurements by Conrad and Marcel Schlumberger. The operation, in France, took more than 5 hours to record the resistivity over an interval of 140 m from a depth of 279 m. Henri Doll, one of the three wellsite engineers at the operation, wrote “We began making our measurements. Someone had to unplug the connector, someone else turned the winch. Someone had to run to the rig floor to look at the counter on the sleeve. I wrote down the measurements on a pad together with the depth... Then it was unplugged, rolled up one meter at a time.” (Schlumberger 2007) Four years later the spontaneous potential of a formation could be measured, thus allowing permeable rock to be distinguished from nonpermeable rock. These measurements are far from the sophistication of today, but for me this demonstrates how seemingly simple innovations have made such a tremendous impact on our industry. The equipment currently used for logging wells and capturing and transmitting data is a far departure from the rudimentary operation that took place 85 years ago. The point is that the industry saw the need for the nascent technology, and its use all over the world allowed not only the measurements around a wellbore, but also provided results with which the geologists could match well correlations, map a field, and obtain the structure of the horizons. Innovative ideas emerging in other industries began to have an impact on our well evaluation operations. The development of electronics in the 1930s led to a number of new developments in logging operations. The miniaturization of rugged circuit boards and components led to new tools that suffered less damage, which in turn reduced lost time during rig operations. The introduction of computers permitted the capture and interpretation of data. Transmission of data from wellsite to office has been enhanced by innovation in the telecommunications world, and remote logging operations have been enhanced by the use of satellite and other forms of telecommunication. Modern technology now permits multilocation access to live data from rig sites, thus permitting real-time management of situations that leads to speedy interpretation. When I worked on a wellsite in the late 1960s, logs were developed on site and physically moved by road, boat, or helicopter to the office-based engineers for evaluation; subsequently, further instruction was transmitted back to the wellsite by unreliable high-frequency radio. I can still recall the smell of ammonia used for printing those logs. I recently mentioned this to a few young engineers and the blank look on their face made me feel as if I was from the Stone Age, but that is what innovation has done in our industry.

In situ deposition behavior of SiO2 on YSZ-TBC-coated IN738LC during a burner rig test

This work was planned as a preliminary test to obtain an optimal condition for in situ deposition of SiO2 on zirconia-based thermal barrier coating (TBC)-coated IN738LC specimens using a burner rig. The effect of the in situ deposited SiO2 on the long-term reliability of TBCs upon cyclic burner rig operations will be tested in the next study. Tetraethylorthosilicate (TEOS), the precursor for the deposition, was fed admixed with methanol into the combustion chamber of the burner rig at an exhaust flame temperature of 1530°C. All five coating processes were selected by varying the concentration of TEOS in the mixture and applied to hollow type pin specimens infixed to the rotating carousel to face the downstream exhaust gas vertically. A total of 1500cc of the mixture at a given vol.% TEOS was fed evenly to the burner rig for 54min during the coating process.After the process, TBC spallation was observed on the front side of the specimens processed with 10, 5, and 2vol.% TEOS, while the specimen of 0.5vol.% TEOS was coated with a ~5μm thick SiO2 layer without any macroscopic damages. The surface of the coatings consisted of fractal-structured nodules at 10vol.% TEOS, and of smooth grains at 0.5vol.% TEOS. The spallation of SiO2-coated TBC was attributed to the thermal mismatch due to the difference in the thermal expansion coefficients of the two materials. Based on these results, the mixing ratio of TEOS to methanol was reduced to 0.3vol.%, which produced a 1–2μm thick, smooth and homogenous SiO2 coating without any spallation of TBC. This deposition condition was chosen for the planned test to evaluate on the effects of the in situ deposition of SiO2 on the long-term durability of TBC-coated IN738LC specimens upon cyclic burner rig operations.

Challenges of Drilling and Completion Operations of Deep Wells in Ultradeepwater Zones in the Gulf of Mexico

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125111, ’Challenges of Drilling and Completion Operations of Deep Wells in Ultradeepwater Zones in the Gulf of Mexico,’ by J.C. Cunha, SPE, and O. Moreira, Petrobras America, and G.H. Azevedo, SPE, B.C.M. Pereira, and L.A.S. Rocha, Petrobras S.A, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. Challenging wells are being drilled in deepwater zones in the US Gulf of Mexico (GOM). Many are in water depths of 8,000 ft or more, with several target reservoirs at 30,000 ft and deeper. Completion challenges include completing multiple zones while trying to minimize future expensive workover operations. Practical experiences dealing with these problems and suggestions to make them manageable are presented. Introduction Exploration, appraisal, and production in areas such as Mississippi Canyon, Atwater Valley, Walker Ridge, Keathley Canyon, and others present inherent difficulties associated with deepwater drilling along with new difficulties in very deep zones that demand careful planning to be reached without compromising safety, well integrity, formation evaluation, and estimated budget. Challenges include difficult-to-find seafloor locations to place the production wells or drilling center. The complex directional drilling requires planning, follow-up, and feedback that must be fine tuned to reduce nonproductive time (NPT) and improve well-construction performance. A “Plan/Do/Check/Act” (PDCA) routine should be implemented. The completion design may include stimulating deep, high-pressured, tight reservoirs. Completing the Lower Tertiary section of deep wells in the GOM proves to be as challenging as the drilling. With few analogous wells drilled and no production history to date, validation of any completion design and the corresponding engineering solution is affected by uncertainties. Weather-related events are a major source of NPT. Ocean currents associated with the Loop Current and Eddies may cause massive losses of time. Moreover, the always unpredictable hurricane season has caused such large losses that many operators will delay an operation rather than try to drill during hurricane season. Weather—Be Prepared To Be Surprised The GOM Loop Current, a stream of warm ocean water that flows northward from the Yucatan Peninsula, loops clockwise and eventually exits through the Florida Straits. The Eddy, or Loop Current ring, occurs when a stream of water “breaks” (shears) and separates from the main stream. The Eddy can be up to 250-km diameter and more than 1000 m deep. Once formed, it travels west across the GOM as it rotates clockwise, completing a rotation once every 10 days. It may take from 2 months to 1 year for an Eddy to dissipate. In a recent operation in the Walker Ridge quadrant, an anchored rig in the presence of strong Loop Current lost significant time while trying to perform mooring operations. A total of 224.5 hours in 13 days of operations (72%) was lost waiting on weather. This type of delay can postpone rig operations and delay development and production. It is recommended that a rigorous monitoring and forecasting service be used to enable accurate predictions of the possible effects of Loop Current and Eddies on planned offshore operations.

Microhole Coiled Tubing Drilling: A Low Cost Reservoir Access Technology

Although the microhole coiled tubing drilling rigs have been used extensively in Canada, their application in the U.S. has been very limited. In an effort to introduce this technology to the U.S. operators, GTI, with the support of DOE∕NETL, has completed a successful field testing of the coiled tubing microhole drilling technology. In this paper we report results of field testing of the system in 25 wells drilled in the Niobrara unconventional gas play of Kansas and Colorado. The objective of the field test was to measure and document the rig performance under actual drilling conditions. In these tests, a coiled tubing drilling rig (designed and built by T Gipson with Advanced Drilling Technologies Inc.) was utilized. The rig operations have continued to improve to the point where it now drills a 3100ft well in a single day. Well cost savings of approximately 30% over conventional rotary well drilling have been documented. A description of the rig and a summary of its performance in the Niobrara unconventional gas play are included. In addition, an estimate of economic advantages of widespread application of microhole drilling technology in the lower 48 states is presented.

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.

Marco Polo Deepwater TLP

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 95331, "Marco Polo Deepwater TLP: Completion Implementation and Performance," by J. Burman, SPE, Exploitation Technologies LLC, and K. Renfro, SPE, and M. Conrad, SPE, Anadarko Petroleum, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. Novel well-completion techniques and exceptional field execution allowed the six well completions in the Marco Polo deep-water tension-leg-platform (TLP) project to be accomplished in world-class fashion. All six wells (17 frac packs) were placed on pro-duction in only 168 days, including 14 days lost because of storms. The full-length paper focuses on how the implementation challenges of completing 17 zones in six deepwater dry-tree wells with a 1,000-hp rig were met and highlights a number of concepts and technical firsts that can be used in other deepwater development projects. Background Field Development. The Marco Polo field in Green Canyon Block 608 in the Gulf of Mexico (GOM) was discovered in 2000. Six development wells were drilled in 2002 and 2003 and were temporarily abandoned to await completion of the TLP. The TLP hull and deck were installed in January 2004 and were designed to accommodate a 1,000-hp completion rig to run riser tiebacks and perform completions. Only 88 persons are allowed on the platform at a time because of U.S. Coast Guard rules, a significant issue for rig operations. Reservoir. Initial reservoir pressures and temperatures range from 6,700 to 7,600 psi and from 115 to 122°F, respectively. Reservoir fluids are undersaturated black oils, with gravity ranging from 30 to 34°API and gas/oil ratio ranging from 700 to 1,000 scf/STB. Completion-Design Overview. Multiple pay sands, low reservoir temperatures, the requirement to gas lift the wells, and the deepwater environment drove the design of the Marco Polo completions. After significant flow-assurance modeling and evaluation, dual-barrier risers with insulating gel and a separate gas lift string were chosen as the upper-completion design. The sandface-completion design focused on risk management during completion operations, with the hardware designed to minimize future intervention risk. The 17 pay intervals in the six wells were developed with multizone, selective single, stacked frac-pack completions, using sliding sleeves with a concentric isolation string for zonal isolation. Multiple chemical-injection points are installed for hydrate, paraffin, asphaltene, and scale prevention. The installation of fiber-optic technology for downhole-pressure and -temperature sensing assisted in well surveillance and hydrate prevention. Fig. 4 in the full-length paper shows a generalized Marco Polo wellbore schematic.

Ram/Powell Deepwater Tension-Leg Platform: Horizontal-Well Design and Operational Experience

Summary A key focus of the Ram/Powell project is to utilize high-rate (>20,000 BOPD), high-volume wells (i.e., reserves several times greater than that of shelf wells) to enhance project profitability. Completions with large 5½-in. production tubing and horizontal openhole gravel packs (OHGP's) exceeding 2,000 ft in length have been implemented successfully. The horizontal OHGP design, the first implemented in the deepwater Gulf of Mexico (GOM), was selected as a means to improve well reliability over prior horizontal completion designs and sustain high production rates without plugging. A high rate of sand-control failure and plugging have plagued prior GOM horizontal non-gravel-packed completions. Achieving high-quality completions is a major project emphasis. Drilling, completion design, and operational experience of the horizontal wells are discussed. Production from the Ram/Powell tension-leg-platform (TLP) development, Shell's third TLP, began in September 1997. The TLP is located at Viosca Knoll Block 956 in 3,214 ft of water. Four wells were predrilled prior to TLP installation. Ten wells are completed. Five are horizontal OHGP's, one is a single-zone cased gravel pack, and the remainder are two- and three-zone-selective cased gravel-packed completions. Rig operations concluded in January 2000.

フーテージコントラクトへの取り組み

Japan Drilling Co., Ltd (JDC) has been carrying out drilling operations under a footage contract in Persian Gulf since December 1999 utilizing a jack-up rig Hakuryu-8. The footage contract is one of the incentive contracts, which is named from a rate is defined by price per foot. The footage contract is a very common contracting style in US land rig operations, while it is not so common in offshore operations, especially in Asia. This report intends to serve as an induction to the footage contract, JDC's approach to the contract, and a result of the first year operations performed by JDC to verify that this type of contact is beneficial for both operators and contractors.The footage contract shifts risks of hole trouble and equipment trouble onto a contractor in footage section; however, the contractor would benefit more from effective and faster operations with less non-productive time. An operator would benefit from the best possible performance by the contractor, hedging the risk of hole trouble to the contractor and completing a well with shorter time.As a result of five wells drilled in year 2000 by JDC, the operator saved 39 days of operating days and 17 percent of operating costs. And those performances were highly appreciated by the operator.

海外オペレーション アブダビ石油におけるリグオペレーション

This paper describes the rig operations of Abu Dhabi Oil Co., Ltd. (ADOC).ADOC has been operating three offshore fields (Mubarraz, Umm Al Anbar and Neewat Al Ghalan) located about 60 to 100km off the coast of Abu Dhabi in Arabian Gulf where fifty-four (54) wells have been drilled. Twenty-five (25) wells out of fifty-four (54) have been completed as electrical submersible pump (ESP) producers. The total number of rig operations has reached to three hundred and eighty-five (385) since the first well was drilled, with half of the operation related to ESP programs. ADOC uses the cantilever jack up type rig because of the shallow water depth and workover re-entry requirement.Typically, about seventy (70) people are on board, from the rig contractor, the service companies and ADOC. As so many people are working on the rig, it is essential to keep good communications with the rig superintendent and the engineers from service companies and have meetings before conducting stimulation, cementing or other sensitive operation. Logistics is also key to efficient rig operation.

Cement Sheath Stress Failure

Summary Observation of the sudden appearance of annular pressure in wells exposed to high temperature changes or excessive internal casing pressure prompted a laboratory investigation to simulate conditions under which cement sheath failure could occur and thereby define the causes, characteristics, and limits of the problem. Cement sheath failure is manifested by interzonal problem. Cement sheath failure is manifested by interzonal annular-fluid movement and abnormally high annular pressure at some point behind the casing up to and at the surface. Cement sheath point behind the casing up to and at the surface. Cement sheath failure can be observed in any producing area where excessive flowing temperatures exist at the surface or where excessive internal casing test pressures are used. The detrimental effects of cement sheath failure are numerous and may include lost revenue from lost production, potentially hazardous rig operations (especially when annular isolation loss creates shallow-water sands supercharged with gas), and potentially hazardous producing operations. Exposure of steel casing to excessive temperature increases or internal test pressures causes diametrical and circumferential casing expansion. This circumferential force creates a shearing force at the cement/casing interface, causing failure at the cement/casing interface or radial fracturing of the cement sheath from the inner casing surface to the outer casing (or borehole) surface.

Simulation and performance analysis of floating drilling rig operations

A computer program that can run on a personal computer was developed to simulate a sequence of drilling tasks such as the drilling and completion of deep water wells. The program can be used for techno- economic evaluations of different vessels competing for the same drill job. It can also be used for long term planning for drill jobs to be carried out at different locations and in different seasons. The simulation has two parts. The first simulates sea states, making use of the Markov approach. The second simulates drill operations. Rig motions are determined by the sea states and compared against operational limits. Work is slowed down or interrupted when limits are exceeded.

Engineering Opportunities and Challenges in Drilling

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleum engineering. Summary This article discusses the role of engineers in drilling. Specific tasks and responsibilities are discussed to show the opportunities and challenges thatare developing with the changes in drilling engineering technology. Introduction The application of engineering technology can greatly reduce drilling costs. We seldom drill as efficiently as we know how; we usually don't even comeclose. A wealth of technology has been developed to cut drilling costs, butthis technology has not yet been integrated into normal field operations. Thereare numerous incentives not to increase drilling efficiency. It requires harderwork for everyone-roughneck, engineer, geologist, manager, and all othermembers of the drilling team. The drilling industry is faced with the challengeof applying modern technology in everyday rig operations. This challenge isgreatest with the many turnkey drilling contractors and smaller operatingcompanies that do most of today's drilling with only limited access toengineering assistance. A thorough understanding of the capabilities andlimitations of drilling engineering is mandatory for field application oftechnology. The drilling business is much more than just drilling engineering. It must effectively blend the application of money, manpower, and materials ina successful combination using many specialists. Drilling engineers could notfunction without the bankers, accountants, salesmen, lawyers, landmen, geologists, geophysicists, truck drivers, mail clerks, and the many others whomake up the drilling team. An effective operation requires everyone tounderstand and appreciate overall company objectives. Drilling engineers at alllevels are responsible for recommending, specifying, and approving expendituresof large sums of money. They often work as drilling foremen or toolpushers, where they are responsible for operations that involve several dozen personnel. It's pretty easy for an engineer to allow his self-importance pretty easy foran engineer to allow his self-importance to be inflated by ego-boostingsubordinates and salesmen. To keep the proper perspective, he must understandthat drilling is only a part of the total exploration and production effort. production effort. A drilling rig is essentially a factory. The product ishole. It must be a high-quality hole to permit geological evaluation andeconomical production when hydrocarbons are found. The engineer's job is toproduce this quality hole economically and safely. produce this quality holeeconomically and safely. Drilling engineers become involved after many othershave completed their work. Leases have been acquired; geophysicists, geologists, and other exploration specialists have selected rig sites; financespecialists have acquired the drilling funds, and legal, tax, insurance, andaccounting specialists have formulated contracts and set up the procedures andcontrols for paying for the drilling services. Drilling engineers are thencalled upon to prepare a well plan. JPT P. 1141

Case History of Yakin Field: Its Development and Sand Control

Summary This paper deals with the development of the Yakin field in East Kalimantan, Indonesia, with emphasis on the sand control methods used. Implementation of an effective sand control program ensured the successful development of this field. Gravel-packed wells had substantially lower production decline rates than the initial completions without gravel packs. Control of sand production also has been demonstrated by the lack of production also has been demonstrated by the lack of sand problems during the 4 1/2 years since the sand control program was initiated. During this time there have been no submersible pump failures associated with sand production. production. The successful sand control program was achieved by a well-coordinated and cooperative effort of drilling, reservoir engineering, production research, and service company personnel. Establishment of communication among all people involved, starting early in the planning process and continuing through the rig operations to the process and continuing through the rig operations to the final production phase, coupled with intensive training at all levels of responsibility, on-site supervision, and quality control were important factors in the success of the development program. Introduction The Yakin field was developed as a joint venture between Pertamina and Union Oil Co. of Indonesia within the terms of a production-sharing contract. The field is located approximately 4 miles offshore East Kalimantan. The field was discovered in April 1976 with the drilling of the Yakin No. 2 well. Yakin structure is a north-northeast-trending anticline, bordered on the north by a normal fault and on the west by a reverse fault. The reservoir is of marine origin, ranging in age from late Oligocene to early Miocene. The main sand has a closure of about 250 acres and an average thickness of 60 ft. The crude oil gravity ranges from 13 to 25 deg. API. More complete reservoir properties of Yakin field are shown in Table 1. The field was developed in two major stages. The earlier development, Phase 1, was completed such that oil recovery from the field could be accelerated. Despite some problems associated with rapid development, early Phase 1 completions provided the experience to allow for Phase 1 completions provided the experience to allow for the proper equipment to be ordered and installed in Phase 2. Phase 2 completions designed to control the sand problems experienced in Phase 1 were started in April 1977. problems experienced in Phase 1 were started in April 1977. Drilling and testing of early wells indicated that sand control would be required to deplete the reservoir efficiently. Sand produced during drill stem testing and low recovery of sidewall cores indicated a poorly consolidated formation sand. The initial three wells of Phase 1 were completed without sand control. Two wells eventually sanded out and the other one was produced at a reduced rate to stop the sand production. These three wells later were worked over and recompleted with inside-casing gravel packs. All the subsequent wells of Phase 2 were completed with open hole gravel packs. In Phase 2 were completed with open hole gravel packs. In some completions the gravel was resin-coated. A brief summary of the overall production characteristics of the Yakin wells is included in Table 2 and Fig. 1. Since a sand-control completion is more complex than a conventional completion, a team approach was initiated to ensure a successful job. A successful sand control project requires that everyone involved has a full knowledge and a thorough understanding of the "do's and don'ts" from the planning stage through the actual sand control job to the production stage. JPT P. 23

Physical Environmental Monitoring In the Offshore

Abstract A summary and review is presented of certain components of a Physical Environmental Monitoring Program conducted by Mobil Oil Canada, Limited. This program is in support of Mobil's East Coast drilling operations. The various meteorological and oceanographic program components are described with specific reference to the use of the data collected by this monitoring program.to collect, record and transmit data on meteorological and oceanographic conditions; andto assist and advise operational personnel on the various meteorological and oceanographic conditions that affect the performance of rig operations. Introduction Physical environmental monitoring is associated with all East Coast offshore exploration drilling operations. Although this paper addresses, in summary form, some components of Mobil on Canada's Environmental Monitoring Program, the program as presented here is in line with those of other offshore operations and fairly representative. The objectives of such a program are four fold:to monitor, in real time, meteorological and oceanographic parameters that influence on-going offshore operations;to record data that can be used to more accurately model and forecast future meteorological and oceanographic parameters that may influence these operations;to archive data for future potential design considerations; andto obtain and retain government approvals to explore and develop. These objectives, in part, are satisfied by Environmental Monitoring Program components, namely:Offshore Ice/Weather Observer ProgramAutomatic Environmental Weather Station ProgramWave Measurement ProgramCurrent Measurement Program Ice/Weather Observer Program The first program component, the Ice/Weather Observer Program, is the cornerstone for a large portion of this environmental monitoring work. Two trained ice/weather observers are stationed on each Mobil contracted drilling rig on a 24-hour basis. Their basic duties are:to collect, record and transmit data on meteorological and oceanographic conditions; andto assist and advise operational personnel on the various meteorological and oceanographic conditions that affect the performance of rig operations. Depending on the drilling area the rig is in. they may also act as the rig's radio operators. This case applies only to Mobil's drilling operation near Sable Island. Some of the duties of the ice/weather observers are carried out in accordance with practices set down by the Atmospheric Environment Services (AES) of the Canadian Government. However, other duties are specific to an offshore drilling operation and are carefully supervised and monitored by Mobil. The most important function of the ice/weather observer is to make meteorological and oceanographic observations. The observations are called MANMAR measurements; MANMAR stands for " Manual of Marine Weather Observing". Observations are generally made every three hours. They are recorded in a report titled " Selected Ships Meteorological Log", which is supplied by AES. An individual observation entails anywhere from 23 to 44 pieces of information. Figure 1 shows the various parameters measured, observed and recorded on this regular schedule. This includes information on winds, waves, and other weather parameters such as low cloud ceiling, visibility, temperature, barometric pressure, ice and icebergs-just about any weather parameter you can

New Developments in Down-Hole Motors for Improved Drilling Performance

This paper discusses improvements in design, materials, and manufacturing of components for down-hole, positive-displacement drilling motors. Significant increases in tool life expectancy result in Moineau-type, down-hole motors that perform much longer under optimum drilling conditions. Research continues to improve the performance of down-hole motor elements. Introduction In its simplest form, a rig-floor rotary table turns a long string of drillpipe and drill collars to transmit rotation and thrust to the drilling bit. The bit usually is powered this way regardless of depth, hole size, or adverse hole conditions. Putting the rotary power at the bit, on the other hand, eliminates the need for fuming the drillpipe and, thus, helps to reduce surface power, and minimizes wear, torsional stress to the drillpipe, and damage to the hole or its protective casing. Using a down-hole motor to power a drilling bit is not new. Indeed, the idea was considered during the days of cable tools, when operators were looking for more efficient drilling methods. This approach to mechanical rock destruction uses forces normal to the rock, with emphasis on bit rotation. The trend is toward more normal bit force and rotation speed, while increasing equipment life. Development of the positive-displacement, down-hole motor using the Moineau principle began in 1956 in the U.S. (Fig. 1). This motor supplies bottom-hole rotational power at greater speeds than rotary power, but without power at greater speeds than rotary power, but without the complexity and cost of turbodrills or electrodrills. This motor does not require that the drillpipe rotate as in conventional rotary drilling. Since drilling torque is directly proportional to the pressure drop across the fluid-powered motor, the fluid-pressure gauge at the surface accurately indicates drilling-bit weight. The tool was tested originally for straight-hole drilling, but was considered uneconomical because of short bearing life and no bits that could operate at high rotational speeds. However, the tool later was such an economic and technical success in directional drilling that, until 1968, almost all research and development was directed toward that end. Since then, further research and development has produced a tool that now is used in straight-hole drilling. Developments that have increased the life and performance of down-hole motors include improvements in the performance of down-hole motors include improvements in the dump-valve assembly, the stator and rotor, and the connecting rod and bearings. These improvements have resulted in motors that have consistently performed more than 100 hours, with drilling weights ranging from 2,300 to 3,300 lb/in. of bit diameter and a rotational speed of 720 rpm. Auxiliary tools, such as the adjustable bent sub, the bent connecting-rod housing, and the alignment sub also have been developed. These tools simplify rig operations and increase the effectiveness of directional drilling with the motors. In the future, further improvements will be realized with the development of improved elastomers for the stators, improved bearing and seal packages, and the introduction of multicavity motors. New Developments Dump Valve Because fluid will not flow readily through the tool without motor rotation, a dump (bypass) valve assembly is provided at the upper end of the tool. provided at the upper end of the tool. JPT P. 993

Cost control of truck service for land rig operations

Cost control of truck service for land rig operations

Value of Heave Compensators to Floating Drilling

This examination of the motion compensator concludes that it is one of the biggest advances made in offshore drilling in recent years. Analysis of the operation of rigs equipped with motion compensators indicates a saving of about 16 days per rig-year. Optimum bit loads allow maximum penetration rates and increased bit life. Another advantage is safety in penetration rates and increased bit life. Another advantage is safety in well killing and BOP-stack handling. Introduction Before the design and introduction of the first heave or drillstring compensators, variations in the distance between the bit and the drilling level owing to wave action were accounted for with the aid of bumper subs. As offshore exploration moved into deeper and rougher water and failures achieved new dimensions in terms of cost, an alternate and more flexible method was sought. The result was the motion compensator first produced in the late 1960's when Vetco Offshore, Inc., installed a twin-cylinder model on the Wodeco IV, a drill barge working in the Santa Barbara channel. This equipment operated successfully within its design limits, and the concept of hydraulic or pneumatic heave compensation was proved viable. At least seven companies are now engaged in the design and manufacture of compensators. Each machine has a mode of operation peculiar to itself and possesses its own series of peculiar to itself and possesses its own series of problems. Shell Expro has been able to analyze the problems. Shell Expro has been able to analyze the performance of both the Vetco and the RUCKER Shaffer performance of both the Vetco and the RUCKER Shaffer models since they were installed on Shell-contracted rigs in the North Sea in Jan. 1974. Operating problems of other models such as the Western Gear Single Cylinder and the Ocean Science and Engineering, Inc., Crown Compensator have been assessed wherever possible. Savings in terms of weather down-time, bit life, and personnel and equipment safety have been observed during the latter part of the winter and throughout the summer of 1973-74 and are discussed in some detail. Now that drilling has moved further north, almost to latitude 62 degrees, the weather has produced a greater impact on rig operations. West of the Shetland Islands, where extremely long swells have been observed with correspondingly high heaves, one rig would certainly have been shut down without a heave compensator. Drilling has continued successfully in weather conditions producing heaves in excess of 12 ft and blowout-preventer producing heaves in excess of 12 ft and blowout-preventer (BOP) stacks have been landed with similar movement. Principles of Operations Principles of Operations Motion compensators may be located in the crown block or between the traveling block and the hook; they may operate either pneumatically or hydraulically, or by a combination of the two. During rig heave conditions, the operating medium is forced back and forth by means of hoses between the compensator's piston/cylinder arrangement and a number of pressure bottles or accumulators (Fig. 1). In the traveling-block units, hydraulic hoses hang from their respective standpipes in the derrick, whereas the compensated crown eliminates these - all hoses are fitted to the outside of the derrick. The mode of operation may be considered active or passive, or a hybrid of the two. In the purely passive passive, or a hybrid of the two. In the purely passive system (Fig. 2), the activating fluid results in air being compressed and expanded in and out of a bank of accumulator bottles; use is made of the adiabatic gas law: p1V1k = p2V2k V1 k p = p2 − p1 = p1 [(--------) −1],.......(1) V1−AX JPT P. 938

Developments in Testing from Floating Vessels

New developments in formation testing equipment provide more safety and better performance in offshore floating vessel operations. A slip-joint safety valve, for example, will help close in a well in certain emergencies. Field tests on another device-the annulus pressure responsive safety valve-have shown that it, too, satisfies pressure responsive safety valve-have shown that it, too, satisfies the unique requirements of such testing operations. Introduction Benefits of formation testing were proved long before off-shore drilling operations were commonplace. This temporary completion service gives the owner valuable information for evaluating well potential. Years of research have been spent in developing tools for obtaining this information efficiently and safely. Stationary offshore rig operations utilized standard land testing procedures; however, this technology had to be expanded for testing from floating vessels under various sea conditions. The unique needs of testing from floating vessels have led to such developments as the balanced slip joint, the slip-joint safety valve, the subsea test tree and the annulus pressure responsive safety valve (APR safety valve). Conventional land testing assemblies were used on the first tests from floating vessels. Since the vessel moved up and down at the will of tides and waves, it was difficult to maintain the drillpipe stationary to keep recommended weight on a packer. Little, if any, specialized safety equipment was available. Introduction of volume-pressure balanced slip joints was a great improvement in the offshore testing string. It allowed testers to set and hold a desired amount of weight on the packer and yet safely manipuulate drillpipe to operate testing tools above the packer. Such slip joints help compensate for wave and tide actions, making safer the task of testing from floaters. Normally, testing tools are opened by applying pipe weight. However, pipe can part up-hole when floating vessels break anchor and drift off location or when unusual wave action is encountered, and this leaves tools in an open position with no down-hole means for closing the well. Development of a slip-joint safety valve was an important interim step in helping prevent such situations. Downward movement of the string automatically closes the valve, thus offering valuable protection. protection. Additional protection in offshore testing became available with the development of the subsea test tree It incorporates ball valves that automatically, shut in a well when pipe above the test tree is removed or when it parts. With the tree, standard blowout protection is still retained. Sometimes it is protection is still retained. Sometimes it is desirable to run longer-than-normal production or drawdown tests in which wells are allowed to flow for as long as a week. Under such conditions seal wear in slip joints, rams, etc., can become a problem. With the subsea tree, which provides a positive hang-off point for all tubular goods, vertical movement of drillpipe is virtually eliminated except during manipulations needed to open and close the testing tools, and seal wear is reduced. The recent introduction of an APR safety valve is a significant step in improving formation testing equipment. This tool offers all the benefits of conventional testing and sampling while providing more safety control during operation. It is unique among such tools in that annulus pressure is used to operated the valve. JPT

Field Welding on Oilfield Tubular Goods

Abstract Examination of several typical samples of field welding of scratcher and centralizer lugs revealed that the quality of welds was inconsistent and generally poor. Damage to the casing could usually be expected. The holding capacity of the welded lugs and of the equipment itself against the lugs was found to be of a very low order. A non-technical summary of the effects of welding on oilfield tubular goods is presented. It is shown that the tubular goods steels require a stricter welding procedure for quality welds than steels in general industrial use. A study of this will give the busy supervisor a fair appreciation of the problem of joining metals by arc welding. Having established the effects of welding, the control of these effects as they concern field application is considered. Welding at the rig site is classed into five categories, namely,welding scratcher and centralizer lugs,welding collars, floating equipment,welding casing hangers,orange peeling of conductor to surface pipe, and finally,welding of casing and tubing as piping. The peculiarities of each category are discussed and recommendations made when applicable. Introduction The frequency of holes in casing set in wells gave rise to the suspicion that the failures were related to the field arc welding done on the casing. The welding of scratcher and centralizer stops or lugs on casing is a common practice. It was decided to determine the quality of field welding of these appurtenances to the casing and to evaluate its effect on the wall body. Several typical samples of field welding of scratcher and centralizer stops were examined and tested. After determining the quality of the welding being done in the field, the next step was to investigate methods of improvement. A review of published literature and consultation with welding engineers provided welding and metallurgical information. Since current laboratory knowledge was not being put to use, translation of the laboratory knowledge into a simple explanation for rig operations was needed. A brief and non-technical discussion of welding on high carbon-alloys steels was prepared to foster a better understanding of the problem by those supervising field welding operations.