Lost Circulation Zones Research Articles

Risk Planning and Mitigation in Oil Well Fields

Lost circulation presents one of the major risks associated with drilling. The complete prevention of lost circulation is impossible but limiting circulation loss is possible if certain precautions are taken. Industry experience has proved that is often easier and more effective to prevent the occurrence of loss than to attempt to stop or reduce them once they have started. The problem of lost circulation was magnified considerably when operators began drilling deeper and/or depleted formations. A strategy for successful management of lost circulation should include preventative (best drilling practices, drilling fluid selection, and wellbore strengthening materials) and remedial measures when lost circulation occurs through the use of lost circulation materials. In this paper the authors present lost circulation zones and causes, potential zones of lost circulation, excessive downhole pressures causes, preventive measures, tools and methods for locating loss zones and determining the severity of loss, lost circulation materials, and recommended treatments.

An experimental study of silicate–polymer gel systems to seal shallow water flow and lost circulation zones in top hole drilling

Abstract Shallow water and lost circulation are frequently encountered problems during drilling top holes of oil and gas wells. Plenty of methods have been applied to overcome these problems. Among these methods, silicate based gels are one of the oldest. For this study, Sodium-Silicate based gel system is investigated experimentally and several aspects of the system are improved for efficient field applications. This improved gel system is deliberately delayed, multi-component system to be mixed as a uniform liquid at the surface facilities but desired to form gel structure where it is placed in the well. Gel slurries are composed of distilled water, Sodium-Silicate solution, polymer solution, lost circulation materials, weighting agent and organic initiator (initiating the gelation). In this study, effect of these components on gel time, gel quality and gel strength at room temperature is investigated as a function of their concentration. In order to compare gelation time of different compositions, a new, easy and consistent gel time determination method is developed. Being based on vortex closure time, the method can be followed easily even by basic rig laboratories. Another new method is introduced to monitor long term gelation process by measuring turbidity (NTU) of the mixtures and plotting NTU versus time curves. In addition, unique observation codes are defined to compare the gel qualities of different compositions. For gel time and quality experiments, Sodium-Silicate concentrations from 3.5% to 15% by weight in the mixture were investigated and the concentrations range of 7.5–10% were found as applicable. It is determined that, gel time is getting higher as silicate–initiator ratio (SIR) increases for these optimum concentrations. The system is improved by addition of two different polymer solutions. These polymers not only improve the elasticity of the final gels but also provide sufficient viscosity to keep weighting agent and/or lost circulation materials (LCM) in suspension. In addition, viscosity development curves obtained from rotational viscometer at various constant shear rates indicated that, gelation is accelerated by applied shear. Furthermore, HTHP filter press cell was modified by manufacturing new bottom cap with 1 mm diameter hole in center to determine the extrusion pressures of the gels and it was found that, extrusion pressure can be increased by the addition of fibrous type lost circulation materials.

A Chemical Lost Circulation Agent for Severe Leakage in Drilling

This study presents a chemical lost circulation agent with some distinct advantages that make it suitable for use in controlling severe leakage during drilling process. It is a granular solid with irregular shape and able to bridge or fill the cracks and other porous or faulty formations into where the drilling fluid is lost. Then this agent will undergo a chemical reaction with water, and the reaction products fill between particles and bind tightly lost circulation agent particles to each others or to the rocks at the lost circulation zone, thus effectively enhance the compressive strength of the cementing body formed by the agent and prevent lost circulation. Temperature, particle size, and additives added have been shown to have a significant influence on the consolidating rate and compressive strength of the cementing body. In addition, the cementing body has certain permeability, and the permeability can be adjusted, so this agent is proper for use to control lost circulation in reservoir.

Estimation of Wellbore and Formation Temperatures during the Drilling Process under Lost Circulation Conditions

Significant change of wellbore and surrounding formation temperatures during the whole drilling process for oil and gas resources often leads by annulus fluid fluxes into formation and may pose a threat to operational security of drilling and completion process. Based on energy exchange mechanisms of wellbore and formation systems during circulation and shut-in stages under lost circulation conditions, a set of partial differential equations were developed to account for the transient heat exchange process between wellbore and formation. A finite difference method was used to solve the transient heat transfer models, which enables the wellbore and formation temperature profiles to be accurately predicted. Moreover, heat exchange generated by heat convection due to circulation losses to the rock surrounding a well was also considered in the mathematical model. The results indicated that the lost circulation zone and the casing programme had significant effects on the temperature distributions of wellbore and formation. The disturbance distance of formation temperature was influenced by circulation and shut-in stages. A comparative perfection theoretical basis for temperature distribution of wellbore-formation system in a deep well drilling was developed in presence of lost circulation.

Colorado Drill-Cuttings-Injection Pilot Results

Summary From December 2007 through April 2011, the operator conducted a two-phase drill-cuttings-injection pilot at the Piceance field in western Colorado to reduce the environmental footprint of drilling operations. This was the first subsurface injection of drill cuttings in Colorado, and it used a lost-circulation zone in the Wasatch G formation as the injection interval. The first phase of the pilot was to assess the technical feasibility and formation response to injection. During this phase, water-based mud and drill cuttings from four wells were injected into a fifth well that was temporarily suspended at the intermediate casing and perforated in the Wasatch G formation. More than 40,000 bbl of fluid was injected during vacuum conditions with confirmed confinement to the target zone. On the basis of the injection results, the pilot progressed to a second phase to assess the logistical requirements of transporting cuttings from multiple drilling locations to a central processing-and-injection site. The injection well selected had experienced lost returns in the Wasatch G when originally drilled and was completed as a dedicated injector. The pilot processed cuttings from three active rigs, and it demonstrated the capacity to process cuttings from more than six rigs. The operator proved injection as a technically feasible option for drilling-waste disposal during full-field development at Piceance.

Parametric Analysis of Wellbore-Strengthening Methods From Basic Rock Mechanics

Summary The authors presented the first industry SPE paper on wellbore strengthening, which proposed a new concept for lost-circulation prevention while drilling (Morita et al. 1988; Fuh et al. 1992; Morita et al. 1996). Recently, the authors were invited to present at the 2010 SPE Forum held at Park City, Utah, USA. This presentation focused on wellbore-strengthening methods currently used in the industry, including well cooling, stress cage, and tip screening of induced fractures. During the forum, participants requested a parametric analysis of these methods using rock-mechanics equations and principles. This paper presents a set of analytical equations developed for parametric analysis of three typical wellbore-strengthening methods (Fuh et al. 2007; Alberty and McLean 2004) and provides information about the strengths and limitations of each method. In addition, an updated set of equations developed on the basis of previous work completed by the authors has been provided to make the analysis of wellbore-strengthening methods easier to implement. The equations can be classified by the length of the cracks to be stabilized, as follows: Borehole strengthening by heating to stabilize 0.0- to 0.1-in. cracks. (Not included in this parametric study.)Borehole strengthening to stabilize microcracks (with mudcake or fine particles) for 0.1- to 1-in. cracks.Borehole strengthening to stabilize macrocracks (stress-cage method) for 1-in. to 2-ft cracks.Borehole strengthening to stabilize a large fracture with the tip-screening method for cracks longer than 10 ft.Parametric studies were conducted on three wellbore-strengthening methods, and the following observations were made:Borehole-stabilization method: Water-based mud mixed with 25/40-mesh particles stabilizes the borehole by plugging the microcracks with mudcake. Borehole stability is enhanced by mixing 25/40-mesh crushed nut shells into the mud. Some drilling engineers enhance borehole stability by intentionally returning a proper range of cutting particles from the shale shakers.Stress-cage method: This method is applicable if the formation permeability is not too low. However, if the permeability is low, a high-fluid-loss pill is required to reduce propagation of the induced fracture and adequately place the granular materials. After wellbore strengthening, ultralow-fluid-loss mud is required during drilling to reduce the pressure buildup in the fracture section behind the seal.Tip-screening method: This method does not require the squeezing of particles to induce a fracture. Mixing particles with drilling fluid prevents fracture initiation, and if a fracture is induced, this mixture prevents further fracture propagation by tip screening. Tip screening is effective if a lost-circulation zone has some permeability, but is less effective if the lost-circulation zone has no permeability.

Overcoming Black Sea Ultradeepwater Drilling Challenges

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 21676, ’Overcoming Black Sea Ultradeepwater Drilling Challenges,’ by Luiz A.S. Rocha, SPE, Edgard G.A. Arduino, SPE, Danilo S. Gozzi, Sandra B. Duarte, Gabriel H. Azevedo, SPE, Luis A.N. Suarez, Jose C.S. Bruno, Bruno C.M. Pereira, and Patricia O.A. Pessoa, Petrobras, prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed. A well-management process that includes design methodology and well-execution procedures was used by Petrobras to drill its first ultradeepwater well in a remote and challenging area of the Turkish waters in the Black Sea (Fig. 1). Ranked as a well of the highest complexity level, this wildcat deepwater well faced a number of expected hazards, such as shallow gas zones, long abnormally pressurized intervals, low-fracture-pressure-gradient sections, lost-circulation zones from the presence of fractured limestone, great potential for false kicks (breathing formation and ballooning), and the possibility of gas migration into the riser. Petrobras also developed a well-classification method that takes into account several factors, including water depth, number of wells drilled in the area, and the existence of abnormally pressurized formations. The main goals of this procedure are to establish the proper well robustness (WR) and to define operations that should be used to mitigate operational problems. Despite all of these challenges, the well was executed according to its original plan, indicating that the method was applied successfully and can be repeated in other wells. Introduction The depletion of old oil fields has caused operators to seek new opportunities in previously unexplored areas. The challenges of these new frontiers and the high cost of drilling usually result in expensive wells. These high costs, in turn, may tempt some operators to implement dangerous cost-reduction techniques. These cuts can lead to underestimated well design, which often leads to the loss of the well and the construction of another one. Thus, the cost reduction expected at the beginning becomes, in the end, a huge and unexpected increase in costs. This paper refers to the drilling of an ultradeepwater wildcat exploration well located in the Turkish Black Sea, in water deeper than of 2000 m (6,560 ft), that reached a final depth greater than 5000 m (16,405 ft). This well was drilled by Petrobras using the fifth-generation semisubmersible Leiv Eiriksson drilling rig, operated by Ocean Rig.

Managing Circulation Losses in a Harsh Drilling Environment: Conventional Solution vs. CHCD Through a Risk Assessment

Summary Conventional drilling techniques used in harsh drilling environments are sometimes impractical or uneconomical. This was experienced while drilling through the reservoir section being investigated. This section is characterized by high pressure and formation fluids estimated to contain 18–20% H2S and 4–6% CO2. The presence of extensive karst/fractures along with severe circulation losses prevents successful drilling using the conventional circulation technique. For this scenario, the pressurized-mud-cap closed-hole circulation-drilling (CHCD) technique was applied, and it proved to be the most effective method to drill through the Lower Carboniferous carbonate. In conventional drilling through such lost circulation zones, the typical method is to isolate the thief formation [lost circulation-materials (LCMs) pills, gunks, and cement plugs] to maintain an overbalanced condition. These methods have their disadvantages: uncertain results, time and cost increase, and damages on well productivity. Furthermore, it may be a long, ineffective process because of multiple leakoff zones or massively fractured zones. Where unsustainable losses occur and conventional circulation is no longer possible, the CHCD technique may be used to allow the continuation of drilling. This technique is not underbalanced drilling. The annulus is closed, and no returns are circulated to the surface. The CHCD is not a simple or an inexpensive system. It is used only when other systems for controlling losses have proved to be ineffective. Large quantities of water and mud are required as well as additional equipment and specialized personnel. An accurate evaluation of several factors has to be performed. Drilling hazards are the major issue because the primary barrier to well influx is jeopardized, but also rig time, material availability, and consumption have to be considered. The aforementioned uncertainties can be addressed through risk evaluations by comparing two drilling scenarios of a typical development well where one uses CHCD technology and the other uses conventional drilling techniques. This paper will discuss the operational details of conducting CHCD as well as the risk-management approach, which involves the identification, evaluation, and mapping of all risks involved in each scenario (qualitative risk assessment). A probabilistic model is, therefore, developed to combine all the risks identified and to address their consequences within operational time (quantitative risk assessment).

Managed-Pressure Drilling To Counteract Lost-Circulation and High-Pressure-Gas Zones: South Wapiti Red Rock Field

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137428, ’Successful Use of Managed-Pressure Drilling To Counteract Lost-Circulation and High- Pressure-Gas Zones: A Case Study From the Red Rock South Wapiti Field in Grande Prairie, Alberta, Canada,’ by Hassan K. Malik, SPE, Raymond J. Litwin, SPE, and Bernard C. Jones, ConocoPhillips Canada, prepared for the 2010 Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed. Use of heavy mud weight (MW) to control high-pressure (HP) -gas and lost-circulation zones at the same time is a challenge. The Red Rock field in the South Wapiti area in Alberta experienced this combination, which resulted in high operational costs, primarily caused by an additional casing string, high MW, and severe mud losses. On average, costs were 20% higher than anticipated, making this drilling program uneconomical. Introduction The Red Rock field is in the Deep basin of western Alberta, where much of the gas is found in low-porosity, low-permeability reservoirs deposited in an epicontinental seaway. The Deep basin is unique in that porous rocks are water saturated updip to the east and gradually become gas saturated and less porous downdip to the west. The Falher section (overlying the Gething formation) is overpressured in the area, but there is more confidence in predicting the presence on a broad scale. Coals are found throughout the Falher and Gething formations and must be considered. Historically, lost circulation has occurred in the Falher section at elevated MWs, also into several coal seams in a few cases. Recent wells have experienced kicks in the Bluesky, Gething, and Falher zones, which have driven MWs higher to manage risk. Further uphole, the Doe Creek and Dunvegan formations have been pinpointed as a main lost-circulation section in the area. Natural fractures exist in the wider area across this section, which supports the determination that these zones cause lost circulation. Red Rock Drilling Challenges Wells in this area are drilled with an invert-oil-based-mud (OBM) system, which is used in the field with consistent success in keeping reactive shales stable. The use of OBM systems, with high oil/water ratios, is costly in lost-circulation situations. Wellbore-strengthening materials have been used to varying degrees to mitigate losses while drilling the usual problem zones. This is seen when drilling into the Doe Creek and Dunvegan formations with low MWs (930–980 kg/m3) and losses are encountered. A regime of adding wellbore-strengthening materials before penetrating these zones helps heal the losses, and in several cases allowed the MW to be increased deeper in the well. This technique is an important tool in this area to drill through loss zones.

Managing Circulation Losses in a Harsh Drilling Environment

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 128225, ’Managing Circulation Losses in a Harsh Drilling Environment: Conventional Solution vs. CHCD Through a Risk Assessment,’ by S. Masi, C. Molaschi, SPE, and F. Zausa, Eni E&P, and, J. Michelez, SPE, Altran, originally prepared for the 2010 IADC/SPE Drilling Conference and Exhibition, New Orleans, 2-4 February. The paper has not been peer reviewed. Conventional drilling techniques used in harsh drilling environments are sometimes impractical or uneconomical. This was experienced while drilling through the reservoir section being investigated. This section is characterized by high pressure and formation fluids estimated to contain 18 to 20% hydrogen sulfide (H2S) and 4 to 6% carbon dioxide (CO2). The presence of extensive karst/fractures along with severe circulation losses prevents successful drilling using conventional circulation techniques. For this scenario, the pressurized mud cap closed-hole-circulation drilling (CHCD) technique was used, and proved to be the most effective method to drill through the Lower Carboniferous carbonate. Introduction Drilling the reservoir section is the most challenging part of the drilling activity that is being carried out at the oil field under investigation. The reservoir is a carbonate platform, and it is well known that carbonate formations (limestone/dolomite) are characterized by the presence of fractures and/or large vugs, and consequently circulation losses frequently occur while drilling. Sometimes losses are minimal, but at other times they are sufficiently large to become total losses. This situation has been experienced often in this reservoir. In fact, in certain areas, unsustainable losses occur and conventional circulation is no longer possible. Therefore, one of the main concerns is the magnitude of losses that could be faced while drilling the reservoir zone. It must be emphasized that when using conventional drilling techniques through lost circulation zones, the standard practice is to minimize losses by attempting to seal off the thief zone before continuing drilling. This usually is done by pumping lost-circulation-materials (LCMs) pills and setting cement plugs so that the mud weight will overbalance formation pressure at all times. However, this is a long and often unsuccessful process because multiple leakoff zones may be encountered in sequence or because massively fractured zones cannot be cured. Furthermore, these methods have several disadvantages: they offer uncertain results, they are time consuming and therefore expensive, and in hydrocarbon reservoirs, they may reduce well productivity. In this scenario, the CHCD technique allows drilling in circulation-loss zones by controlling the annulus pressure and injecting a sacrificial fluid into the thief formations, thereby minimizing the nonproductive time and costs typically required to implement the traditional methods of circulation-loss control. For this field, CHCD was determined to be the most effective method to drill through the carbonate reservoir.

Novel Thermal Technology Uses Two-Wellhead Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120413, ’A Novel Thermal Technology of Formation Treatment Involves Bi-Wellhead Horizontal Wells,’ by R.R. Ibatullin, SPE, N.G. Ibragimov, SPE, R.S. Khisamov, A.T. Zaripov, and M.I. Amerkhanov, Tatneft, originally prepared for the 2009 SPE Middle East Oil and Gas Show and Conference, Bahrain, 15-18 March. The Republic of Tatarstan possesses significant reserves of heavy oil and bitumen. The first pilot project on heavy-oil production through vertical wells dates back to the 1970s. A number of thermal methods were tested including in-situ combustion, cyclic-steam stimulation, and gas/steam-mixture injection. However, all these methods demonstrated their insufficiency. In 2006, a new pilot project was launched. This is a modified technology of steam stimulation through a pair of U-shaped horizontal wells. Introduction There are many applications of the steam-assisted gravity-drainage (SAGD) method in Alberta, Canada. The efficiency of the SAGD method greatly depends on the presence of water-saturated and shale interlayers in the reservoir section. In 2006, a new pilot project was launched in Ashalchinskoye field to test a modified low-pressure SAGD technology using a unique pair of U-shaped horizontal wells (two-wellhead wells) (Fig. 1). This technique overcomes some disadvantages of classic SAGD technology. This deposit occurs at approximately 78 m and has a rather complex structure. Water-saturated interlayers are found in the top and in highly oil-saturated zones of the formation, while shale stringers are found in the middle of the sequence. Both aquifers and tight, low-permeability, calcareous sandstones or a low-saturated reservoir can serve as the bottom of the formation. New Solutions To date, three pairs of U-shaped horizontal wells have been drilled in this area, with the length of horizontal wellbores from 200 to 400 m. The wells were drilled with a vertical drilling rig, hitting the surface at an angle, thus having two wellheads–vertical and slanted. Two parallel horizontal wells were completed with sand screens and were drilled one above the other at a vertical distance of 5 m between them. The process monitoring is carried out through vertical evaluation wells, and a fiber-optic cable is used for temperature measurement along the horizontal wellbore. The wells were completed by swabbing until mud and solids stopped being produced; then, steam was injected into both wells with the subsequent placing of the lower well on pump production; temperature was monitored along the wellbore length to determine lost-circulation zones and to control the profile of the wellbore heating.

Use of Liner Drilling Technology as a Solution to Hole Instability and Loss Intervals: A Case Study Offshore Indonesia

Summary The Banuwati field offshore southeast Sumatra, Indonesia, presents major challenges to both drilling and liner running operations because of the problematic lower Baturaja limestone formation, which is a carbonate reef structure known for severe lost-circulation conditions. The operator previously had experienced severe losses with wellbore-stability issues while drilling this formation with the inability to set the 7-in. drilling liner at the planned depth in Well A-3. The liner had to be pulled out of the hole, leading to the eventual abandonment of the existing openhole section and resulting in the sidetracking of the well. Liner-while-drilling technology was identified as the most suitable solution for setting the planned 7-in. drilling liner through the loss interval because of the following: Documented lost-circulation problems have been minimized or eliminated through the use of liner drilling technology possibly attributed to the "smear effect" (Fontenot et al. 2004) phenomenon.The liner system selected provided for high torsional capability as well as the requirement for both a mechanical and a pressure event to release the setting tool, thus minimizing the chances of premature release.A drill shoe with a displaceable polycrystalline-diamond-compact (PDC) cutting structure was used to drill the 8½-in. hole section and subsequently displaced before cementing so as to allow drill out with a conventional drill bit and bottomhole assembly (BHA). This paper will discuss the implementation of liner drilling technology in the Banuwati field project. This technology was used to drill successfully through the known lost-circulation zone with the 7-in. liner cemented in place, allowing the operator to reach the completion objectives while realizing a savings of more than USD 1 million.

Evaluation and Optimization of Low-Density Cement: Laboratory Studies and Field Application

Summary Cementing a string in one stage is a challenging task, especially in the presence of weak formations. Cement-slurry losses during placement are highly possible if the equivalent-circulating density (ECD) exceeds 11.0 lbm/gal during placement. A conventional method to overcome this challenge is to use multistage cementing by setting the stage tool above the lost-circulation zone. However, field data indicate that the tool can fail, thus causing serious delay and economic losses. In addition, stage tools are considered weak points and are not good for a long-term seal. A second method for zonal isolation is to use low-density cement (LDC). In this study, we considered cementing the intermediate and production casings in the S-1 (sandstone) and S-2 (carbonate) shallow formations and the BJD (dolomite) deep formation in a single stage using lower-density cement based on hollow microspheres, at 9.4 lbm/gal. The shallow conditions simulated in the laboratory tests were 150°F curing temperature, 2,400-psi conditioning pressure, and 1,800-psi confining pressure for 3 months. The deep conditions were 260°F curing temperature, 5,000-psi conditioning pressure, and 3,000-psi confining pressure, also for 3 months. Hollow-microspheres cement was used in oil and gas wells without encountering any operational problems. However, the high cost of microspheres cement was a limitation for potential field application. In this study, we present extensive laboratory work to optimize hollow-microspheres LDC by the elimination of microfine cement from the blend. Experimental studies (shrinkage, compressive strength, porosity, gas and brine permeability, and chemical analysis of cement) were conducted to determine the effect of this optimization on the properties of cement. Data generated during the 3 months supported the use of the optimized system to cement casings at the shallow conditions tested. The removal of microfine cement did not reduce the compressive strength, with an average of 2,013 psi; no shrinkage was observed, and no increase in permeability was noted during the three months of testing. The use of the optimized system did help in bringing cement to the surface in one stage. The cost of the optimized blend was 40% less than conventional hollow-microspheres LDC. This paper presents case histories that include job design, job execution, and evaluation of the LDC. Field treatments were successful and maintained isolation for more than 3 years.

Technology Update: Top-Drive Casing-Running Tool Solves Tough ERD Problems

Over the past 15 to 20 years, top-drive technology has brought substantial improvements in efficiency and safety to drilling operations. However, casing-running methods have evolved more slowly and have not taken advantage of all the potential offered by top-drive drilling. Weatherford International has designed its new Overdrive system for running casing and drilling with casing to make full use of the weight and power of top drives (Fig. 1). The system won a Spotlight on New Technology Award at the 2007 Offshore Technology Conference. This top-drive casing-running system was used recently by Shell to land casing on bottom at more than 18,200 ft depth on a troublesome North Sea extended-reach-drilling (ERD) well with hole restrictions caused by inability to clean the hole completely. Torque-Drive Tool The centerpiece of the technology is the torque-drive tool that combines several conventional casing-running tools into one—power tongs, main hoisting elevators, bails and single-joint elevators, a fill-up/circulation tool, and a weight compensator. All system operations are remote so that no personnel are required in the derrick or on the rig floor, resulting in a significantly lower safety risk (Fig. 2). The removal of equipment and scaffolding from the rig floor also creates a safer work environment. The torque-drive tool is connected below the rig's top drive and can be run with any topdrive system. To run casing, the tool's integral bails and single-joint elevators are used to retrieve each joint or stand of casing, lift it into the derrick, and lower it into position for makeup. The torque-drive tool is then hydraulically clamped onto the casing, and the connection is made up using the rotational power of the top drive to transfer the torque through the torque-drive tool and casing connections. A key component used in conjunction with the torque-drive tool is an integral electronic-load cell called the torque sub, mounted at the top of the torque-drive tool and used to measure the makeup torque of the casing connections. The sub is independent of the top drive and measures true torque, as opposed to conventional techniques that calibrate torque from the voltage that supplies rotational power to the top drive. This new level of accuracy is especially important when making up premium connections, which require torque-turn monitoring and a very low margin of torque-measurement error. Once the connection is made up, the driller can instantly perform a number of operations as needed, including fill-up of the casing string while lowering, and simultaneous circulation, rotation, and reciprocation of the entire casing string. This combination enables the driller to overcome virtually any unexpected hole problems, such as ledges, lost-circulation zones, shallow-water flows, and swelling formations. This greatly enhances the ability to run the casing string to bottom in a predrilled well.

Continued Evolution of the One-Trip-Expansion, Single-Diameter Wellbore

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17437, "Continued Evolution of the One-Trip-Expansion, Single-Diameter Wellbore," by A. Filippov, SPE, and D. Zijsling, SPE, M. Akhideno, SPE, Shell, and K. Waddell, S. Costa, B. Watson, and B. Bell, Enventure Global Technology LLC, prepared for the 2005 SPE Offshore Technology Conference, Houston, 2–5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission. With more than 300 commercial installations in place, solid-expandable-tubular technology has proved to be a viable and economically feasible alternative to conventional drilling technology. The need for lower lifting costs and to maximize recovery has provided the impetus for the latest step change toward the one-trip section, single-diameter wellbore. In addition to the unique equipment needed to expedite this game-changing technology, new implementations essential to realize the tool components and contingencies had to be developed and tested. The full-length paper explains the overall design and testing approach necessary for the construction of a single-diameter well. Introduction Installation of successive single-diameter expandable liners will revolutionize the way many wells are designed and executed. The potential cost savings of an ultraslim wellbore and maximized reservoir potential have been well documented. Single-diameter technology offers the following benefits.Significant increases in potential lateral reach.Significant increases in potential lateral and trouble time.Improvements in capital efficiency on drilled wells and overall field development. This technology allows enhanced field-development flexibility and cost reductions in many worldwide field developments. For example, increasing lateral reach and thus reservoir contact and drainage creates the potential for reduced well count and greater production per well. More production from fewer wells can lower the number of wells required and result in reduced drilling costs. Reduced trouble time and risk lowers drilling costs. This drilling optimization can result in lower facility and project capital requirements. Field Applications Use of single-diameter expandable-casing technology has the field-proven potential to reduce drilling and completion costs significantly. These savings are realized by reducing drilling risk and resultant trouble time by successively isolating problem lithology and/or underpressured zones while preserving a single-diameter wellbore. Gulf of Mexico (GOM) operators, who often encounter severe lost-circulation zones at shallow depths, are watching this technology development in hopes of expanding long drilling liners to isolate these underpressured zones and later case off the expanded liner and problem zones. Successive installation of expandable, single-diameter wellbores can reduce the friction/drag forces that can limit lateral reach while preserving a single-diameter wellbore as deep as required. This application can provide higher weight on bit than conventional drilling technology at comparable depths.

Reverse Circulation Placement Technique vs. Conventional Placement Technique: A Comparative Study of Cement Job Hydraulics Design

Abstract Reverse circulation cement placement technique (RCCPT) has been suggested asan alternative for providing proper annular coverage for lost circulationzones. It is generally believed that RCCPT helps minimize the circulationpressure and hence, allows cement placement with no apparent losses. A basic hydraulic design study is conducted to determine the anticipatedpressure losses during the cement jobs run by using both the RCCPT and theconventional cement circulation placement technique (CCCPT). Results have shown that, for each design case (i.e., wellbore geometry andthe rheology of cement slurry), there is a critical depth above which theequivalent circulating pressure (ECD) with RCCPT can be higher than ECD with CCCPT. Examples of typical cement job design calculations are provided toillustrate the changing ECDs as a function of depth during both RCCPT and CCCPT. Introduction Lost circulation is one of the most common problems encountered whencementing a well. The problem becomes increasingly critical, particularly whencementing fractured formations such as the ones encountered in geothermalwells, and coal bed methane wells, or low fracture gradient zones near sea bedsin offshore wells. Primary cementing of these zones using the conventionalcement circulation placement technique (CCCPT) has been very difficult, evenwith lightweight and foamed cement. Reverse circulation of cement placement technique (RCCPT) has been offeredas an alternative to eliminate some of the problems experienced when cementingpotential lost circulation zones(1–5). Marquarie and Brisac(1) reported successful applications of RCCPT in the North-Hassi-Messaoud Field in Algeria. Using RCCPT, they were able to cement aweak Triassic formation above the casing shoe without allowing the plasticclays (above the weak zone) to extrude and salt water to enter the well. Griffith et al.(2) conducted large scale experimental tests to investigatethe advantages of RCCPT. They have suggested that RCCPT is a viable option tolower equivalent circulating densities during the cementing process. They havealso found that reverse circulation of cement on primary cementation neitherincreases nor decreases the displacement efficiency. Griffith et al.(2) alsooutlined a procedure for a typical reverse circulation cementing operationconducted by coal bed methane producers in the area of Trinidad, CO, in the U.S.

Geology and hydrogeology of the Dammam Formation in Kuwait

The Dammam Formation of Middle Eocene age is one of the major aquifers containing useable brackish water in Kuwait. Apart from the paleokarst zone at the top, the Dammam Formation in Kuwait consists of 150–200 m of dolomitized limestone that is subdivided into three members, on the basis of lithology and biofacies. The upper member consists of friable chalky dolomicrite and dolomite. The middle member is mainly laminated biomicrite and biodolomicrite. The lower member is nummulitic limestone with interlayered shale toward the base. Geophysical markers conform to these subdivisions. Core analyses indicate that the upper member is the most porous and permeable of the three units, as confirmed by the distribution of lost-circulation zones. The quality of water in the aquifer deteriorates toward the north and east. A potentiometric-head difference exists between the Dammam Formation and the unconformably overlying Kuwait Group; this difference is maintained by the presence of an intervening aquitard.

Evaporite karst of Northern Lower Michigan

Michigan has three main zones of evaporite karst: collapse breccia in Late Silurian deposits of the Mackinac Straits region; breccia, collapse sinks, and mega-block collapse in Middle Devonian deposits of Northern Lower Michigan, which overlaps the preceding area; and areas of soil swallows in sinks of Mississippian deposits between Turner and Alabaster in Arenac and Iosco counties, and near Grand Rapids in Kent County. The author has focused his study on evaporite karst of the Middle Devonian deposits. The Middle Devonian deposits are the Detroit River Group: a series consisting of limestone, dolomite, shale, salt, gypsum, and anhydrite. The group occurs from subcrop, near the surface, to nearly 1400 feet deep from the northern tip of the Southern Peninsula to the south edge of the “solution front.” Glacial drift is from zero to 350 feet thick. Oil and gas exploration has encountered some significant lost-circulation zones throughout the area. Drilling without fluid returns, casing-seal failures, and lost holes are strong risks in some parts of the region. Lost fluid returns near the top of the group in nearby areas indicate some karst development shortly after deposition. Large and irregular lost-circulation zones, linear and patch trends of large sink holes, and 0.25 mile wide blocks of down-dropped land in the northern Lower Peninsula of Michigan were caused by surface-and ground-water movement along faults into the Detroit River Group. Glaciation has removed some evidence of the karst area at the surface. Sinkhole development, collapse valleys, and swallows developed since retreat of the glacier reveal an active solution front in the Detroit River Group.

The Hydraulic Effects of Lost Circulation and the Implications for Contaminant Migration During Drilling

AbstractThe impact of lost circulation during rotary drilling near an existing monitoring well cluster was evaluated by periodic measurements of water levels and contaminant concentrations at the well cluster. Due to regulatory concerns, changes in water levels or VOC concentration in the well cluster during drilling would trigger monitoring well redevelopment. The borehole was drilled approximately 30 feet northeast of four nested monitoring wells that screen Devonian and Silurian carbonate bedrock at depths of 15, 60, 130, and 190 feet. Following complete circulation loss at depths of 177 and 1 S3 feet in the borehole, a rapid decrease in water levels was observed in the upper three monitoring wells. The water level in the well that was screened through the lost circulation zones increased slightly.Decreasing water levels in formations located above the point of circulation loss appear to occur in response to a sudden decrease in borehole fluid pressure caused by the flow of drilling fluid into the formation. The relative contribution of contaminated formation water lo the borehole can be estimated by using the time‐drawdown relationship and estimates of transmissivity. At the point of circulation loss, significant dilution of contaminant concentrations occurs from the loss of drilling fluid into the contaminated zone. Contaminated formation water entering the borehole during periods of complete lost circulation may mobilize contaminants from upper lo lower formations. Lost circulation into a formation would be signaled by a water level increase in monitoring wells. The wells would subsequently require development to remove the volume of fluid lost to the formation, including both drilling fluid and contaminated formation water. Monitoring wells exhibiting declining water levels following lost circulation would not require development since drilling water has not entered the zones screened by these wells.

Cementing of Fragile-Formation Wells With Foamed Cement Slurries

Summary Substantial regions of hydrocarbon production in California consist of formations that are very fragile, which imposes a density limit on the cementitious system used to cement the well pipe. Also, troublesome fallback problems have been experienced for years in these areas. problems have been experienced for years in these areas. Fallback can possibly reduce production by causing formation damage. Usually, the use of foamed cement offers a low-density cementitious material that develops adequate compressive strength while avoiding fallback problems that are caused by density. After hardening, foamed cement has reduced density, and it usually provides the advantages of temperature stability and heat insulation properties. In this paper, the properties of foam cements are discussed and paper, the properties of foam cements are discussed and more than 60 cementing jobs completed with foam cement are summarized. Introduction The recent availability of foam cement as an oilwell services product has offered a new procedure to circulate cement slurry past formations having exceptionally difficult lost circulation tendencies. Certain areas of California hydrocarbon production are overlain by several highly permeable, unconsolidated sand and gravel bed permeable, unconsolidated sand and gravel bed formations that have very low reservoir pressure and low fracturing gradients. Also prevalent are naturally fractured shaly sands and shale formations that consistently pose lost circulation problems during the drilling and cementing operations on wells located in Kern County, CA. If circulation is maintained to the surface during cementing and cement returns are achieved, fallback often occurs such that the top of set cement is found many feet (often hundreds) below ground level. Therefore these formations are incapable of supporting the hydrostatic load exerted by conventional-density cement slurries throughout the cement hardening period. In the past, numerous attempts have been made to cement these types of fragile formations. The use of ordinary lightweight cements extended with bentonite, fly ash silicates, perlite, diatomaceous earth oil emulsions, or gilsonite, as well as the use of thixotropic cement slurries, has been attempted, but when applied to exceptionally pressure-sensitive lost circulation zones these slurries have provided limited success. To a large degree, the conventional slurries have not been successful because their densities can be lowered only to approximately 11 to 12 Ibm/gal [4.9 to 5.4 kg/m 3] (1.32 to 1.44 specific gravity) before their useful strength and permeability properties are compromised. Multistage techniques that properties are compromised. Multistage techniques that use conventional lightweight cement slurries also have afforded limited success. In addition, the total cost of this type of approach can be prohibitive. Two types of cement slurries currently are available that can achieve densities much lower than 11 Ibm/gal [4.9 kg/m 31. The first type incorporates pressure-resistant hollow microspheres into cement slurries. High-strength microsphere slurries continue to be used successfully in oilwell cementing. The relatively high bridging ability of the hollow beads enhances their effectiveness in controlling lost circulation. The second available type of ultralow-density cement slurry results from the preparation of a stabilized, gas-containing foam cement slurry. preparation of a stabilized, gas-containing foam cement slurry. Foam cement is successful because of its ability to keep cement slurry density below the hydrostatic breakdown gradient of the sensitive formations. A general comparison of typical physical properties of conventional and foam cements is given in Table 1. It was reported earlier 12 that foam cement could be used to seal underground storage caverns, insulate wellbores, and perform remedial squeeze jobs. Subsequent reports substantiated the basic properties of foam cement. Relatively little information properties of foam cement. Relatively little information has been published that describes the use of foam cement in primary cementing applications. This paper will focus on the use of foam cement as a primary cement in severe lost circulation zones in California. Properties of Foam Cement Properties of Foam Cement A true foam cement is created when a gas is chemically and physically stabilized as microscopic cells within an ordinary cement slurry. Two uncommon factors are needed to prepare stable foam cement. First, the cement slurry should contain a high calcium ion and high-ph-tolerant foaming surfactant and foam stabilizer. Second, the slurry should be conveyed through an effective mechanical foam-generating device that imparts sufficient energy and mixing action with pressurized gas to prepare uniform gas bubbles of the correct size. Foam cement so prepared is essentially stable, unlike nitrified cement or drilling fluid; the gas does not coalesce and separate from the slurry if the slurry remains under the pressure conditions for which it was designed. Nitrogen usually is the first choice of gas since current nitrogen servicing equipment is more than capable of providing sufficient quantities of gas at suitable rates for cementing purposes. Fig. 1 illustrates the quantity of nitrogen per barrel of cement slurry needed to prepare low-density foam cements. JPT P. 1049