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Abstract A comprehensive buckling model, a group of fourth order non-linear ordinary differential equations, was derived by applying the principle of virtual work. Lateral friction force is included in this model. The equations were normalized to make the solutions independent of the wellbore size, type of pipe and mud. The critical sinusoidal buckling load of tubing with different boundary conditions typically seen in drilling and well completion applications was analyzed based on the analytical solution of the linearized buckling equation. The results show that the effect of the boundary conditions can be neglected when the dimensionless length of tubing is greater than 5p. The authors further investigated the effects of friction on sinusoidal buckling by applying the principle of virtual work. The critical conditions for initiating sinusoidal buckling were determined by a group of three non-linear equations. A perturbation solution of these non-linear equations was obtained. It was found that the critical loads for sinusoidal buckling will increase by 30% to 70% for friction coefficients between 0.1 to 0.3. The authors also conducted an experimental study. The experimental results, including both data obtained by the authors and results published by other researchers, support the proposed model. Introduction Various pipes, including drill pipe, casing, tubing, coiled tubing, and sucker rods, are widely used in drilling, well completions, formation stimulation, water injection, and the pumping of wells. During drilling, completion, production, or stimulation operations, the drilling pipe or tubing may be subjected to some degree of axial compression, or the pressure inside the pipe may exceed the external pressure. In both cases, the pipe may lose its stability and buckle into a sinusoidal or helical shape. Consequently, stability and post-buckling analysis of pipe in various kinds of wellbores attracts intense interest from the petroleum industry. J.C. Cunha (2004) and R.F. Mitchell (2006(b)) presented an extensive review on the subject of buckling of tubulars inside wellbores.
- Research Report > New Finding (0.86)
- Research Report > Experimental Study (0.68)
Abstract There are now a variety of ways to achieve higher recovery factors from heavy oil reservoirs, but most of them involve the injection of thermal energy or chemicals to reduce the oil viscosity. While these techniques have been highly successful, they can also be very expensive when the steam generation and/or chemical injection costs are accumulated throughout the productive life of the field. A lower cost solution, one that has been very successful in the Faja Del Orinoco of Eastern Venezuela, is to use multi-branched wells (multilaterals) to increase reservoir exposure and achieve an arguably higher recovery factor. These multilateral wells have been shown to produce more oil over a longer period of time than conventional horizontal wells without any additional operating costs. This paper will discuss the concept of using multilateral wells as an alternative to conventional Enhanced Oil Recovery (EOR) techniques in heavy oil reservoirs. It will argue that the oil recovery factor of a reservoir that is drilled with increased wellbore exposure can be comparable to thermal/chemical EOR under the right circumstances, and that the project will have a much lower operating cost. While steam injection has become the successful mainstay of most EOR projects, there are many drawbacks such as the costs of the steam generation and the emission of greenhouse gases. Multilateral wells can potentially offer an option to produce the same reservoir with lower costs while still recovering an increased percentage of the oil from the reservoir. This technique is especially applicable in inter-bedded or thin oil zones where steam injection would be costly and inefficient. Extensive background information will be presented from the Orinoco belt in Venezuela, where multilateral wells have proven to be an economical approach to develop a very challenging "extra-heavy" oil reservoir. The Petrozuata Project The Petrozuata project is a joint venture between ConocoPhillips (50.1%) and PDVSA (49.9%), to produce, upgrade, and commercialize extra heavy crude oil from the San Diego field, which is located in the Zuata region of the Orinoco Belt in eastern Venezuela. The joint venture operates under a 35-year production contract. Early blend production began in 1998 and the commercial sales of upgraded (synthetic) crude began in 2001. In 2004, Petrozuata achieved record volumes, producing more than in any year since its start-up in 1998. This increase was largely the result of extensive use of advanced drainage architecture and multilateral wells. The main oil reservoir in the ยจFaja del Orinocoยจ are the Miocene sands of the Oficina formation. In the Petrozuata area, the reservoir is described as aggrading coastal plain deposits consisting primarily of massive multistoried and/or stacked, coarse-to-fine-grained fluvial channel belts prograding from south to north. The sands are poorly- to well-sorted and unconsolidated. They have net-to-gross sand ratios of approximately 55 to 65%. Within the primary oil reservoir, the permeability ranges from 700 to 15,000 millidarcies (mD). The channel morphologies vary from highly sinuous silt-filled, laterally stacked to straighter, braided channels. The channel sands are typically 20 to 40 feet thick and as wide as 1 to 2 kilometers (3000 to 6000 feet). By their nature, they tend to be laterally discontinuous and contain a certain percentage of silts (non-reservoirs) within the channel complexes. To achieve high performance wells, the percentage of high-quality oil sand contacted along the horizontal well length must be maximized. Careful geological planning and well design can allow several disconnected sand units to be produced from a single well. Such provisions greatly improve oil recovery and increase well production. To do so, however, requires the strategic placement of horizontal sidetracks and multilateral junctions. Reservoirs range in depth from 1700 to 2500 ft TVD, with average temperatures of 120 to 125ยบF. The oil gravity lies between 8.5ยฐ and 9.5ยบ API, a range that qualifies the oil as "extra-heavy." The reservoir itself is a low pressure, viscous fluid environment that requires significant physical encouragement to get the thick oil to flow. "Drain" is actually a more appropriate term than "flow" because the wells are drilled so closely together and with such frequency that the oil is essentially drained from the sand, under the force of gravity, into wellbore tubulars from which it can be pumped to the surface.
- South America > Venezuela > Orinoco Oil Belt (0.45)
- North America > United States > Texas > Jim Wells County (0.24)
- North America > United States > California > San Diego County > San Diego (0.24)
- South America > Venezuela > Eastern Venezuela Basin > Oficina Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > San Diego Field (0.99)
Cementless Multi-Zone Horizontal Completion Yields Three-Fold Increase
Maddox, Bradley Dean | Wharton, Molly (ECA Holdings, L.P.) | Hinkie, Ronald Lee (Halliburton Energy Services Group) | Balcer, Brent Powell (Halliburton Energy Services Group) | Farabee, Mark (Halliburton Energy Services Group) | Ely, John W. (Ely & Associates Inc.)
Abstract This case-history paper presents an account of the application of expandable (swelling) packers and a hydrajet perforating stimulation technique to perform a cementless completion and hydraulic stimulation in a 350o F, openhole horizontal well of 15,700 ft total vertical depth (TVD). Resulting production was more than three times that of an offset vertical well. The first Wilcox Meek 2 well in the Brazos Bell Prospect Area was drilled and completed to test the effectiveness of horizontal well technology in tight-sand formations. This paper presents the cementless completion process and explores the effectiveness of horizontal-well technology in tight sands by comparing initial horizontal-well production rates to those of offset vertical wells. The well, which was the first horizontal Wilcox in the area and probably the deepest horizontal well completion for a sandstone reservoir in South Texas, used a 5 ยฝ-in. / 3 ยฝ-in combination string as a production string. The 3 ยฝ-in casing was run in the openhole horizontal lateral section and extended into the 7 5/8-in liner casing. It employed five swellable packers, strategically placed on the string to facilitate isolation for optimum stimulation results. An additional swellable packer, larger than the previous five, was run on the top of the 3 ยฝ-in casing string and was placed inside the 7 5/8-in casing to help ensure complete isolation of the annulus. The swelling packers were activated over an 18-day period by hydrocarbons present in the oil-based mud (OBM) in the annulus. Following packer activation, four fracture-stimulation operations were conducted in a non-cemented hole using a unique fracturing technique that incorporates hydrajet perforating with coiled tubing (CT). This technique allows formultiple stimulation treatments to be performed in series without the CT being removed from the hole, larger stimulation stages, and maximum surface-area exposure to the fracture pressure without formation damage caused by cement. Introduction The Wilcox formation is composed of gas-producing sandstone. High-temperature, high-pressure formations such as the Wilcox have reported temperatures of 350ยฐF and above with typical geo-pressured conditions found below 12,000 ft in the onshore Texas Gulf Coast area. Zones of interest are located at ~15,500 to 15,700 ft TVD with porosities ranging from ~26 to 30%, and permeability of 0.001 md. The purpose of drilling the Foster Farms Deep #1-H well was to test a 2,000-ft horizontal section of the Wilcox Meek 2 formation in the Brazos Belle prospect area of Southeast Texas. Vertical wells previously drilled in this area were successfully completed and fractured stimulated in the Meek 2. Over time, these wells have exhibited stabilized production of less than 1 MMcf/D of gas after initial flow rates that exceeded 3 MMcf/D. While these wells are considered economical, a decision was made to use the latest technology in horizontal drilling and completion in an effort to enhance the productivity of Meek 2 wells drilled in the Brazos Belle area. Drilling Operation Since this was the first horizontal Wilcox well in the area and the deepest horizontal well drilled to the Wilcox in South Texas, the drilling program was modified to aid the successful drilling and completion of the 2,000 ft lateral section. The geometry of the borehole was designed to drill in the direction of the least horizontal stress to maximize wellbore stability, intercept most of the natural fractures (if any) in the reservoir, and obtain the best permeability of the producing formation while trying to minimize the tortuosity during the completion.
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- (3 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion (1.00)
Experimental Study on Cuttings Transport With Foam Under Simulated Horizontal Downhole Conditions
Chen, Zhu (U. of Tulsa) | Ahmed, Ramadan Mohammed (U. of Tulsa) | Miska, Stefan Z. (U. of Tulsa) | Takach, Nicholas E. (U. of Tulsa) | Yu, Mengjiao (U. of Tulsa) | Pickell, Mark B. (U. of Tulsa) | Hallman, John Henry (Weatherford International Ltd.)
Abstract The use of drilling foams is increasing because foams exhibit properties that are desirable in many drilling operations. A good knowledge of cuttings transport efficiency under downhole conditions is essential for safe and economical foam drilling. Previous cuttings transport studies with foam are limited to low pressure and ambient temperature conditions; no experimental study has been conducted under downhole (i.e. elevated pressure and temperature) conditions. This paper presents an experimental study of cuttings transport with foam in a horizontal annulus under simulated downhole conditions. Experiments were conducted to determine the effects of polymer additives, foam quality, flow velocity, temperature and pressure on foam cuttings transport. Experiments were carried out at elevated pressure (100 psi to 400 psi) and temperature (80?F to 170?F) conditions in a unique full-scale flow loop with a 73-ft long test section (5.76โณ ร 3.5โณ concentric annulus). A field-tested commercial foam system consisting of surfactant (1% v/v) and Hydroxylethylcellulose polymer (HEC) was used in the experiments. Three different polymer concentrations (0.0%, 0.25% and 0.5% v/v) were tested. Foam quality was varied from 70% to 90%. During a test, cuttings were injected continuously to the flow loop until a steady state condition was established in the test section. In-situ cuttings volumetric concentration in the test section was determined using nuclear densitometers, load cell measurements, and by weighing cuttings flushed out of the flow loop. Test parameters recorded during the experiments were: liquid and gas injection rates, cuttings weight in injection and removal towers, mixture density, friction pressure loss, pressure and temperature in the annulus. Two flow patterns, stationary cuttings bed and fully suspended flow, were observed during the cuttings transport tests. The flow pattern depends on polymer concentration, foam quality and annular velocity. Annular flow velocity, foam quality and polymer concentration all affect cuttings transport efficiency and frictional pressure loss. This paper will help to better design foam drilling and cleanup operations. Introduction Foam is a highly attractive alternative over conventional drilling fluid because it has low density and flexibility in ECD control. However, it is difficult to obtain reliable predictions of ECD for foam drilling because of the complexity of foam flows. When drill cuttings are present in the wellbore, the foam-cuttings mixture affects bottomhole pressure (BHP) and this makes the already complicated compressible foam flow even more complex. Therefore, cuttings transport with foam should be well understood for accurate bottomhole pressure and ECD estimation. In short, a good knowledge of foam hydraulics and cuttings transport is a must for safe and economical drilling. Studies on cuttings transport using foam fluids are very limited. Though cuttings in foam affect hydraulics calculations and ECD predictions, it is generally accepted that foam is very efficient in cuttings transport in vertical wells. Foam flow velocity with 120 ft/min is sufficient for most vertical well foam drilling; in some cases, flow velocity as low as 70 ft/min has been reported to be successful. For foam drilling in horizontal wells, the situation is quite different compared with that in vertical wells because:the particle settling velocity is perpendicular to foam flow direction so that drill cuttings tend to settle to the low side of the wellbore; the density of drill cuttings is much higher than the density of foam. As a result, the mechanisms that govern cuttings transport are different for horizontal wells. Empirical correlations and models developed for vertical wells may not be valid for horizontal and inclined wellbores[1].
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.90)
Successful Horizontal Drilling in Western Siberia: Use of Appropriate, Cost-Effective Technology Solutions to Increase Well Productivity
Diyashev, Iskander (Sibneft) | Lishchuk, Vasiliy Yurivich (Sibneft) | Aker, Gokhan (Schlumberger) | Bustos, Oswaldo (Schlumberger) | Prakash, Leslie (Schlumberger)
Abstract The introduction of Western horizontal drilling techniques into Siberia has achieved outstanding results for Sibneft, a Russian independent operator. Before 2000, vertical or directional S-shape wells were being drilled to develop the Sibneft-NoyabrskNeftegaz oil fields using local techniques provided by Siberian drilling contractors. An alliance with a major Western service provider made possible a Western-Russian design group familiar with all available options. The group created an ideal marriage of Western and Russian fit-for-purpose equipment, procedures, and techniques for a cost-efficient horizontal well design. The methodology applied in this project is a fusion of classic Russian drilling techniques, i.e., compact rigs skidding on a rail system with aluminum drillpipe with Russian turbines to drill tophole sections, coupled with modern horizontal technology such as steerable motors and mud pulse telemetry measurement-while-drilling (MWD) and logging-while-drilling (LWD) systems. To date, 90 wells have been drilled with a progressive learning curve enabling wells to be drilled to around 4000 m (with more than 1000 m of horizontal section) in less than 48 days that at the start of the campaign were taking more than 100 days. The successful integration of these cost-effective solutions has been pivotal in helping Sibneft approach its production targets. Today the 90 wells drilled in the last 3 years (out of 4,500 total wells) account for approximately 175,000 BOPD, or one quarter of total Sibneft production. The cooperation of reservoir and drilling engineering teams from the service provider and the operator was critical to project accomplishments. Introduction Sibneft Oil, an independent operator in Russia with crude reserves of 8 billion bbl, holds major interests in Western Siberia. The oil fields found in this region account for almost 90% of total company crude reserves. Horizontal well technology was introduced in 1999 as a means of improving recovery rates, which had seen significant decline by as much as 50% in the early 1990s. Based on initial studies, a pilot project was initiated in January 2000 with four horizontal wells being drilled in that year. The wells averaged 3500 m in measured depth (MD) with 500- to 600-m horizontal drain lengths. Production results in three wells exceeded expectations on average by 45% to 60 % (Table 1). Time and cost to complete the wells were much higher than planned, mainly because the local crews had very little experience in drilling horizontal wells. Nonproductive time (NPT) averaged around 48% with well costs in the region of U.S. $1.6 million to U.S. $1.8 million. While the results in the pilot phase were encouraging, it was quickly realized that a strategy to capitalize on existing resources and develop new cost-effective technologies was required to make the project economically viable.
Abstract This paper describes a method of predicting formation pore pressure and permeability in a horizontal well during the drilling phase of a well development. Dependable and more accurate information about reservoir parameters such as permeability, pore pressure are indispensable for taking proper well completion decisions at a stage when the formation damage is minimal. In this study, a technique is described which can be used as an onsite tool for the evaluation of formation properties for horizontal wells. Method of analysis is based upon the buildup data collected during a test conducted at various stages of the wellbore penetration in the horizontal section while drilling. Modified well testing theory pertaining to horizontal wells is used for the interpretation of the test results. Examples of using simulated data are provided to demonstrate the practical application of the method. These examples using the proposed approach elaborated in this paper illustrate its practicability and the ease of usage as an onsite tool. Introduction Although many horizontal wells are drilled there seems to be no study in the area or method to estimate the reservoir properties while drilling. Qualitative assessment and quantitative characterization of the reservoir properties is of critical importance in many phases of the well construction. However, the estimation of these properties at the drilling stage of the well development may be more accurate, as the formation damage will be minimal. This not only allows subsequent adjustments to the well plan when combined with payzone geo steering tools but also successful completion of horizontal wells. The present technique based on the transient pressure analysis of early time data gives an estimate of the reservoir properties for a horizontal well. During regular rotary drilling operations, the borehole pressure is kept higher than the formation pore pressure to prevent formation fluid influx into the wellbore. Under controlled conditions, the wellbore pressures can be brought down intentionally below the formation pressure such that the formation influx enters the wellbore. During shut-in condition, casing and drill pipe pressures increase as a function of time due to compressibility of formation fluid. Surface pressure on the drill pipe and casing can be recorded during the buildup period of the test. The pressure buildup data, recorded during the shut-in time, time of influx and the pit gain as a result of influx can be used for determination of formation pore pressure and flow properties, with the interpretation technique presented. The paper presents a method of data analysis (obtained on an intentionally induced influx) to evaluate formation pore pressure and permeability. Basic concepts of transient flow are used by considering a pressure buildup test that follows a variable rate drawdown. The variable flow rate influx occurs because the flowing bottom hole pressure decreases as formation fluid with density less than the drilling fluid density enters the borehole. The approach used in the regular well test can not be applied for the proposed method because the flow rate of the formation fluid-taking place at the sand face during the influx is unknown. The concept of equivalent flow rate and flowing time is extended in this study to account for this variable flow rate.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Today's energy necessities have produced an increment in drilling activities all around the world. Among this situation is the tact that all the operators are trying to minimize cost without reduction in quality. So, they are looking for new types of contracts between all drilling companies, Contractors, services and suppliers. in this paper, we will present some experiences in types of drilling contracts in east Venezuela. It will include some operational benefits and difficulties that will come up while applying each type of contract. It is important to point out the highest commitment of all companies involved versus traditional day-rate contracts. So tar, as a drilling contractor new contracts have involved INTEGRATED DRILLING AND WORKOVER SERVICES, with Operator. ALLIANCES with Operator and Major Services Companies. BONUS-PENALTY based in an operational target time. LUMP-SUM with Operator. CREW INCENTIVES with Operator. Another type of contract that is called DRILLING SERVICES MANAGEMENT is just stating to develop soon. Results show that in all the eases, if drilling crew is considered and a higher participation of the drilling contractor is permitted, it has created a structure to add real value on drilling activities. Additionally, the application of each new type of contract depends on operator necessities and the commitment of each drilling contractor and service company to take the challenge. P. 619
Abstract In 1994 and 1995, a study was initiated to investigate developments, activity, and philosophies of the larger oil and gas industry in implementing horizontal well and extended reach technologies. To date, North American and European operators, contractors, service companies, government authorities, and educational institutions have been interviewed directly along with the development of data resources and references. Over 100 people shared in direct interviews, constituting 13 operators in Europe, 14 operators in North America, 2 drilling contractors, and 5 major manufacturing/service companies. Over 40 person-to-person interviews were accomplished in North America and Europe. Any company specific information shared in the interviews were given in confidence in that the companies would not be identified in any summary results; thus this paper refers to industry findings. Interviews along with approximately 1000 references and industry well information provided a detailed look at horizontal well and extended reach technology industry along with application strategy and philosophy. Introduction While not a new concept, horizontal well technology and extended reach drilling technology have rapidly been employed in the international oil and gas industry since 1987. Before this time, applications were considered emerging. Early efforts of the modern horizontal well industry were led by Atlantic Richfield (short and medium radius) in the late 1970s, Elf Aquitaine in the early 1980s (long radius), and BP Alaska (long radius) in the mid 1980s. Estimates by Philip C. Crouse and Associates, Inc. places worldwide implementation of horizontal well technology at over 11,000 horizontal wells during the last ten years. Use of horizontal well technology has been predominantly applied in the development cycle of a field and a very limited use for exploratory and delineation efforts by industry. One emerging application is for improved oil recovery efforts involving water floods, CO2 floods and other improved recovery methods. Interview Technique and Limitations From October through November of 1994 and from May to June of 1995, key interviews were arranged with operators and service companies. For North America, seventeen different interviews were held with fourteen different operators representing operators who have drilled about 2000 horizontal wells and a very limited number of extended reach wells. The operators interviewed represented about 20% of horizontal wells drilled in North America. For Europe, thirteen different operators were visited as well as others. European operators interviewed accounted for an estimated 80% of all European horizontal wells and extended reach wells. Information given by individual companies was checked against public records maintained by regulatory bodies and on-line services, where such records are collected. Interviews were requested with the operator knowing a broad subject area was to be discussed. When requested, a three page guide to questions was sent. Interviews were requested with either a team or individual areas of a company engaged with the technologies. Areas requested to be covered included the following general areas:General experiences and reasons to use technologies Limits of experiences Company organization for technologies Well locations Geoscience efforts Reservoir description and modeling efforts Drilling considerations and efforts P. 157
- Europe (1.00)
- North America > United States > Alaska (0.24)
ABSTRACT Phillips drilled a 4000' horizontal oil well at 6048' true vertical depth in a depleted (1 lb/gal equivalent mud weight) sandstone reservoir in Caddo Co., Oklahoma, to combat gas coning problems. Seven external casing packers were set in the slotted liner for production control. Initial production from the well was 1800 barrels of oil per day (BOPD) with little gas. INTRODUCTION The West Cement Medrano Unit, a 3700 acre oil field in Caddo Co., Oklahoma, was originally drilled in the 1940's (see Figure 1). Gas production is re-injected for reservoir pressure maintenance, The 240' thick oil layer is underlain by a static water leg (see Figure 2). The top of the reservoir sand is about 5950' true vertical depth (TVD). Production from the 21 vertical production wells has been severely limited by gas coning in the high-permeability (100-500 mD), 200' thick Medrano sandstone. The low drawdown of a horizontal well would solve the gas coning problem, and allow much higher production rates from the reservoir. The plan was to place a horizontal well 80' above the oil/water contact, and 160' below the gas/oil contact to minimize coning of either gas or water. Several conditions in this field made drilling a horizontal well, the West Cement Medrano Unit #71 (WCMU #71), challenging. First, the reservoir pressure is 300 psi, which is about 1 lb/gal equivalent mud weight (EMW). Second, the reservoir fracture gradient is 6.5 lb/gal EMW. And third, the reservoir dips about 23 degrees to the southwest. The reservoir and production engineering requirements established for drilling of WCMU #71 were as follows:4000' of horizontal wellbore is required to drain Block B of the reservoir. The wellbore should be placed in a + /- 10' high vertical window to reduce coning problems. The TVD of the lateral wellbore will be 6048'. The wellbore should be placed in a 100' wide horizontal fairway to avoid contact/intersection with the existing vertical producers or their fractures, and to stay in the desired part of the sand. A slotted production liner will be used, with external casing packers (ECP's) every 500' to provide production control.
- North America > United States > Oklahoma (1.00)
- North America > United States > Kansas > Clark County (0.24)
- North America > United States > Oklahoma > Anadarko Basin > West Cement Field (0.99)
- North America > United States > Oklahoma > Ardmore Basin > Caddo Field (0.97)
SPE Members Abstract Formation evaluation measurements in conventional steerable assemblies are lagging 30 ft - 100 ft behind the bit. This paper describes a fully instrumented steerable downhole motor recently introduced and proven in several North Sea horizontal wells. The tool makes real time measurements of inclination, gamma ray and resistivity acquired at, or close to, the bit. These measurements, integrated into the steerable motor, have enabled complex horizontal wells to be drilled successfully. Provision of inclination at the bit measurements enabled the well site engineers to continually determine the directional behavior of the bottom hole assembly. The reservoir entry point was determined immediately the bit penetrated the formation, gamma ray and resistivity measurements were used to correlate the position of the bit relative to offset wells. The use of the new instrumented motor enabled a specific horizon within the reservoir to be accurately followed. The paper discusses operational aspects of the new instrumented motor. A case history is presented along with data from other field trials which include comparisons between data acquired by the instrumented motor and that acquired by conventional Logging While Drilling (LWD) tools run in the same hole section. Introduction Over recent years horizontal drilling has become established as a routine method of reservoir development. The productivity increase of horizontal wells over conventional deviated wells is one aspect which makes horizontal drilling attractive. However, smaller hydrocarbon accumulations and thinner objective formations are now being developed. The advent of horizontal wells has made these developments possible in many cases. The desire to maximize production from the small reservoirs has led to more and more challenging horizontal wells being proposed. Fundamental to the successful drilling of horizontal wells is LWD data and MWD directional data. LWD tools provide information which enables evaluation of the formations penetrated by the wellbore, and directional readings allow the well path position to be accurately plotted. The data determines how the borehole direction should be changed to achieve the desired objectives of the well. Steering horizontal wells based on geological information has been christened with the term geosteering. A significant disadvantage which has arisen when steering within tight tolerances is the distance of the various data sensors behind the drill bit. This distance varies from 30 ft to 100 ft in a conventional LWD geosteering assembly. The data lag means that changes in formation are established after significant further hole has been drilled. Also, the directional results of the steered section are seen late. In critical applications these disadvantages can mean the difference between maintaining the well within the objective and losing valuable productive hole. In a typical North Sea horizontal well, the effect of a reduction in net horizontal hole from 2000 ft to 1000 ft is approximately 30% of productivity. A recently developed tool overcomes many of the problems of data lag. This tool is a fully instrumented steerable downhole motor providing data at the bit to enable operational decisions to be made more quickly and with a greater degree of confidence. This tool not only provides the primary formation evaluation logs, but also gives hole inclination readings at the bit. P. 455^
- Europe > United Kingdom > North Sea (1.00)
- Europe > Norway > North Sea (0.82)
- Europe > North Sea (0.82)
- (2 more...)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 210/25a > Tern Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > West-Central Viking Graben > Block 9/13 > Ness Field > Lewis III/IV Formation (0.98)
- Europe > United Kingdom > North Sea > Northern North Sea > West-Central Viking Graben > Block 9/13 > Ness Field > Heather Formation (0.98)
- (5 more...)