Fracture Gradient Research Articles

Increasing the Wellbore Pressure Containment in Gulf of Mexico HP/HT Wells

This article discusses the application of two wellbore pressure-containment integrity (WPCI) treatments that substantially increased the pressure-containment integrity in 852 ft of open hole in the last sidetrack for a production hole section. These treatments ultimately made it unnecessary to set pipe early, which could have jeopardized the commercial discovery of the lower gas sand. Earlier sidetracks attempted unsuccessfully to bypass the loss/flow problems that would not allow drilling ahead and increasing the 18.0-lb/gal mud weight (MW) to drill into a high-pressure zone on a deep, high-pressure/high-temperature (HP/HT) well in the western Gulf of Mexico shelf in offshore Louisiana. Various conventional lost-circulation material (LCM) treatments were used without success, increasing the hole's pressure containment. The WPCI treatments raised the leakoff test (LOT) across the entire 852 ft of open hole to 19.1 pounds per gallon equivalent (ppge) vs. the lower LOT of 18.26 ppge before the first WPCI job. LOTs were performed before and after each of the two WPCI treatments to measure improvement in the open hole's pressurecontainment integrity. This LOT data indicated that apparent fracture gradients can be simultaneously increased in multiple rock layers with various types of weak formations exposed in long, open holes by inducing near-wellbore stress fields created from WPCI treatments (Webb et al. 2001; Kelley Sweatman and Heathman 2001; Sweatman et al. 2001; Sanad and Waheed 2003). This approach can then allow use of increased mud weights (MW) and drilling pressures to prevent excessive gas influx from high-pressure sands without lost circulation (LC) in adjacent weak zones. Also discussed are the WPCI treatment design and job procedures, including treatment optimization by the analysis of data from openhole wireline/logging while drilling (OHWL/LWD) logs, cuttings lithology, fracture-seal location indicators (torque on bit [TOB]/weight on bit [WOB]), and before/after LOT pressures. Real-time operations (Kulakofsky et al. 2002) (also described) enabled remote expert analysis and support so that wellsite personnel could: (1) interpret formation characteristics for optimized treatment design, and (2) analyze treatment pressure/rate data for selective placement of WPCI sealants.

Overview: Drilling and Cementing Technology (February 2007)

2006 confirmed foreseen changes. The demand for oil was near the offer or production capacity and the rather stable high oil prices induced new drilling programs. The result was a drilling-rig market with use near 100% and new rig construction for the offshore fleet nearing 100 rigs. The wake-up was rather sudden. If current programs use mostly conventional drilling technology while constant technology evolution improves productivity, new prospects soon will require new drilling technology. Papers highlighted here and listed for additional reading describe recent technology advances. R&D programs in 2005 and 2006 anticipated the need for new technology.In the ultradeep offshore, water depth more than 10,000 ft, conventional riser architecture has reached its limit; the hyperstatic riser is one solution.In deep prospects and extended-reach wells that require multiple intermedi-ate casings, monobore architecture renders these projects feasible.In deep buried reservoirs, the effects of high temperature require careful review of the cement formulation.In some mature or shallow unconsolidated prospects with low fracture gradients, the use of ultralight cements may be required.For production from acidic environments, long-term cement-sheave durability must be studied. Noticeable efforts have been made to improve more-conventional drilling.Understanding drillstring behavior and taking into account contact forces related to string bending will improve trajectory prediction, and its monitoring will certainly increase the overall rate of penetration.Various methods of cuttings disposal exist, and the understanding of cuttings reinjection is improving.The reliability of cement-bond logs has improved with respect to zone isolation, especially when communication tests are impractical or cost-prohibitive. Drilling and Cementing Technology additional reading available at the SPE eLibrary: www.spe.org SPE 99105 "Durability of Oilwell Cement Formulations Aged in H2S-Containing Fluids" by E. Lecolier, SPE, Inst. Français du Pétrole, et al. SPE 98124 "Ultralightweight Cementing Technology Sets World Record for Liner Cementing With a 5.4-lbm/gal Slurry Density" by D. Kulakofsky, SPE, Halliburton, et al. SPE 99005 "First Hyperstatic Riser Joint Field Tested for Deep Offshore Drilling" by Y. Poirette, SPE, Inst. Français du Petróle, et al. SPE 98965 "Advancements in 3D Drillstring Mechanics: From the Bit to the Topdrive" by S. Menand, SPE, École des Mines de Paris, et al.

Estimation of formation fluid pressure using high-resolution velocity from inversion of seismic data and a rock physics model based on compaction and burial diagenesis of shales

Accurate assessment and prediction of formation fluid pressure and fracture gradient form an essential part of the planning process during various phases of hydrocarbon exploration and exploitation; these include regional basin analysis and basin high-grading, prospect identification, analysis, and drilling campaign to lift hydrocarbons. While the literature is full of activities in this field that are linked to the need for drilling safety by providing help with casing and mud weight program—and quite justifiably so—very little discussion addresses another, and very important need: seal integrity and trap configuration analysis.

Integrated wellbore-quality and risk-assessment study guides successful drilling in Amazon jungle

Significant lost-circulation and wellbore-instability problems in the form of bit balling, stuck pipe, and adverse mud-shale interactions have been experienced in wells drilled prior to the study at three prospects in the Amazon jungle. An integrated borehole-stability and risk-assessment study has been carried out to enable successful drilling by optimizing borehole fluid pressures and predicting safe openhole times in various troublesome zones. The guidelines for hole-cleaning parameters and well-trajectory optimization have been obtained using improved fracture gradient and horizontal stress-anisotropy proprietary models based on special drill-cuttings data. Monopole and dipole sonic and imaging logs along with drilling data from the prospect wellshave been used to determine in-situ stresses, rock properties, andformation strength. These parameters have been utilized in borehole stability, hole cleaning, and open-hole time analyses for a comprehensive risk assessment and for selection of the optimum wellpath and drilling design. The wellbore pressures required for borehole stability turned out to be the highest for vertical wells and lowest for the horizontal ones, making drilling of highly deviated and horizontal wells attractive for the prospects. As a result, a wellpath with high deviation in the direction of maximum horizontal stress has been recommended as the most stable choice. The recommendations have been incorporated in the well design and implemented in the field with real-time borehole stability monitoring to result in successful drilling and efficient project economics.

Gravel Packing Long Horizontal Wells With Low Fracture Gradients

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96396, "The Dynamic Bottomhole Pressure Management: A Necessity to Gravel Packing Long Horizontal Wells With Low Fracture Gradients," by Z. Chen, SPE, and R.J. Novotny, SPE, BJ Services Co., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October. Unconsolidated formations are commonly found in offshore reservoirs where long and ultralong horizontal wells are required to produce heavy oil economically. Gravel packing is an efficient and cost-effective sand-control practice for these high-permeability, large-porosity, low-fracture-gradient formations. Successful placement of the gravel-pack completion requires that these low-fracture-gradient wells not be fractured during gravel placement. A dynamic-pressure-management scheme is critical to maintain bottomhole pressures (BHPs) in the required range. Introduction Horizontal-well openhole screen completions have been performed for years and offer many advantages. These advantages can be offset quickly by failure if the job is not carefully designed and executed. This is especially the case for wells with long and ultralong horizontal wellbore sections in unconsolidated formations with low fracture gradients. Although horizontal openhole gravel-pack completions have continued to gain acceptance as reliable completion techniques, they are still under development and often encounter new challenges. In some cases, there may not be any safe operational windows under conventional operation procedures. Dynamic BHP Management During gravel placement in horizontal wells, BHP must be monitored constantly to avoid fracturing the formation. Any excessive leakoff will cause a screenout and, thus, an incomplete sand-control completion. To ensure a successful packing job, an effective BHP-management scheme needs to consider both job-design time and actual job execution. Gravel-Packing Model The gravel-packing physical phenomenon in a horizontal well can be described as alpha-/beta-wave packing. Several flow patterns can be encountered in a given section, affecting the pressure-gradient/flow-rate relation. During alpha-/beta-wave packing, a stationary bed is created at the bottom of the flow path and a heterogeneous mixture of solid particles and carrier fluid flows through the upper part (Fig. 1). The stationary bed at the bottom of the flow path builds up and grows forward like a wave; it is from this that the expression "alpha wave" is derived. The flow path or void above the alpha wave will be packed after the alpha wave packs forward to the bottom of the screen. In the alpha-/beta-wave model, it is assumed that the space above the alpha wave will be packed backward to the top of the screen. The packing process during this phase exhibits a pistonlike movement, packing all the space backward, and is named the beta wave (Fig. 2).

Using Nonparametric Optimal Transformations—Field Applications in the Middle East

Accurate prediction of formation fracture gradient is essential to many petroleum-engineering operations. Proper planning and execution of deep abnormal pressure wells, stimulation treatment, and reservoir exploitation require, among other factors, good estimates of fracture gradient. It has been proven in the literature that most of the available fracture gradient correlations do not provide reliable results when exposed to data away from the geographical region where they were initially developed. A new approach for fracture gradient prediction based on nonparametric optimal transformations is presented. The transformations are totally data driven and do not assume any a priori functional form. The model presents the fracture gradient as a function of pore pressure gradient, rock density, and depth. The data set used in the study consists of more than 21,000 points taken from 16 wells drilled in seven different geologic prospects covering more than 200 mi2. The excellent results obtained from the proposed model establish a new simple tool for fracture gradient calculation that is based on readily accessible parameters. The proposed model is illustrated and validated using several examples from different fields in the Middle East. The results of the various cases confirm that the computed and the measured fracture gradient values are in excellent agreement with an average absolute relative error of 6% and a standard deviation of 0.05 psi/ft.

Deepwater, Subsalt Drilling From Nova Scotia, Canada - Case Study

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98279, "Pore Pressure Prediction and Drilling Challenges: A Case Study of Deepwater, Subsalt Drilling From Nova Scotia, Canada," by C. Marland, SPE, and S. Nicholas, SPE, Halliburton; W. Cox, EnCana Corp.; C. Flannery, SPE, Murphy Oil Sdn. Bhd.; and B. Thistle, Nexen Inc., prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21-23 February. Offshore eastern Canada is an environment where deep water and the need to penetrate thick salt sheets increase the difficulties faced by drillers. The full-length paper details a deepwater, subsalt-drilling case history and examines the challenges of dealing with high pore pressures and variable fracture gradients. During drilling, conditions were encountered that required use of unconventional borehole sizes and on-the-fly drilling-design modification to deploy unplanned equipment rapidly. Introduction The Weymouth A-45 well is approximately 160 miles south by southeast from Halifax, Nova Scotia, Canada, in the deepwater area of the Scotian shelf. Seismic analysis identified the presence of a subsalt anomaly, the 150-m-thick Argo salt sequence. This sequence presented a potential drilling challenge and also a problem for prewell pore-pressure and fracture-gradient planning. Because of the challenges posed by the deepwater environment and the thick salt deposit, the well included a complex well design with concentric hole openers and an unconventional casing design. Despite potential hazards and complex well design, the drilling program allowed flexibility in decision processes and in well design to deal with problems encountered. Flexibility was particularly important when drilling through the salt body with a point-the-bit rotary-steerable system (RSS). Although the RSS was not planned for use below the salt, the success of the system in the shallower parts of the well led to its use below the salt and highlighted the flexibility of rotary-steerable technology. Planning and Design In August 2002, three seismic lines and six offset wells were used for initial analysis of the Weymouth Prospect. These data were used to generate overburden, pore-pressure, and fracture-pressure predictions. The six offset wells, including two deepwater wells, showed two different pore-pressure regimes unrelated to water depth. The first pore-pressure regime was characterized by normal pore-pressure gradients to approximately 2900 m followed by a slow increase in pressure, averaging 22 kg/m3 equivalent circulating density (ECD) per 100 m through to total depth (TD). The second pore-pressure profile had a steeper pressure "ramp" from 3600 m with a rapid pore-pressure increase to 1800 kg/m3 and greater by well TD.

Top seal development in the shale-dominated Upper Devonian Catskill Delta Complex, western New York State

The preferential generation of vertical natural hydraulic fractures at the contact of the Upper Devonian Hanover gray shale and overlying Dunkirk black shale of the Catskill Delta Complex, western New York State, suggests that the latter served as a hydraulic top seal to formation fluids migrating upward from deeper in the sediment pile. Petrophysical properties and small-scale textural characteristics of these siliceous fine-grained rocks confirm the crucial role of depositional environment and sequence stratigraphic position of a shale lithotype in determining its sealing capacity. The especially high sealing capacity of the basal interval of the Dunkirk shale, inferred early high-stand systems tract (HST) strata, reflects the anoxic depositional environment of these deposits that favored the preservation of their abundant organic matter and finely laminated depositional texture. The absence of bioturbation enabled the undisrupted sediment, notably carbonaceous clay-rich laminae, to undergo rapid mechanical compaction, platy grain reorientation, and porosity reduction. Compaction-induced squeezing of ductile organic matter into void spaces further reduced pore throat diameters. Immediately underlying heavily bioturbated deposits of the organic-lean Hanover shale, inferred upper HST or low-stand wedge sediments, accumulated in a dysoxic depositional environment. Disruption of layering and homogenization of sediment by burrowing organisms produced a more porous and permeable microfabric through which formation fluids moved only to be arrested by the high capillary entry pressures at the base of the Dunkirk shale. Natural hydraulic fractures, some of which propagated into the Dunkirk shale, formed when fluid pressure at the top of the Hanover shale reached the fracture gradient. The high sealing capacity of the basal Dunkirk shale was probably enhanced by its finely laminated nature and the generation of biogenic methane, both of which contributed to the formation of a near-impermeable gas capillary seal.

Techbits: Deepwater Heavy-Oil Challenge Extends to Reliable Completions

Optimized sandface and wellbore production-systems technologies intended to maximize both productivity and hydrocarbon recovery in deepwater developments were the focus of a 3-day Applied Technology Workshop (ATW) held in Brazil. Keynote speaker Ricardo Beltrao of Petrobras set the stage for the meeting by giving an overview of the challenges the energy industry is facing to produce heavy oil in deep water and by offering a glimpse of the challenges ahead. Following an agenda in which the majority of time was designated for problem solving, ATW participants heard presentations and discussion by subject matter experts, identified gaps, and then met in groups to categorize issues of concern in the following subject areas: chemicals, sand control, artificial lift, and reservoir. In the area of chemicals, discussion centered on these existing gaps for producers: - For new developments, mechanical devices are available to minimize the necessity for chemical solutions; however, such solutions are not offered on existing wells. - A process to divert scale inhibitor and remove scale in horizontal wells is needed. - A more permanent reduction of permeability to water is required. - Chemicals to prevent emulsion and organic/inorganic deposition need to be formulated. With regard to sand control, gravel packing long horizontal wells in low-fracture-gradient scenarios remains a major concern. Workshop attendees concluded that not only does the industry need to better understand fines migration in the heavy-oil environment, but it must somehow gather and connect all data from completed wells. Sand control should be approached from the standpoint of the entire operation. Of particular interest was the need to address washouts and to correctly estimate the fracture gradient. While low-density proppant plus beta and diverter valves can be used, the issue of cake removal remains. An accurate method of measuring the filter-media opening must be found to handle the mobile fraction of fines in the formation in addition to a means of measuring fines size and quantity. Is it possible to standardize comparative testing of screens, such as laser vs. sieve? A predictive technique would be extremely useful in measuring the impact of produced solids on surface equipment and filters. In an unconsolidated heavy-oil environment, taking a close look at the impact of injection above fracture pressure in gravel-packed wells is key. Currently, there exists a lack of data for injectors and for determining the appropriate method of sand control. It was emphasized that existing models for light-oil scenarios are inaccurate in predicting the potential deposition of asphaltenes and scale in the heavy-oil environment. Dialogue in the artificial-lift arena included whether electrical submersible pumps could handle gas when marginal heavy-oil fields required injection. Also, possible production of sand in flowlines represents a major problem, particularly in ultradeep water. In addition to discussion on aspects of reservoir modeling, sand prediction, and compaction prediction, water-influx and -coning control were deemed essential. Compartmentalization, in which control can be exercised over each segment, offers a solution, but while packers can isolate each single joint, they cannot eliminate water coning. The use of intelligent control devices for monitoring and control was suggested to achieve maximum efficiency.

Estimating the fracture gradient coefficient using neural networks for a field in the Middle East

Fracture gradient constitutes an essential parameter in the pre-design stage of drilling operations, reservoir exploitation and stimulation. Over the years, fracture gradient has been acknowledged to be one of the most important key element that needs to be accurately determined in order to achieve optimum operation results. Several calculation methods have been presented in the literature for different regions of the world. All of these techniques were based on either parametric or empirical correlations, which require a prior knowledge of the functional form. Moreover, these methods are only valid at the area where they were developed. This paper presents an artificial neural network model to predict the fracture gradient for the Middle East region. The data set used in the study consists of more than 21,000 points with fracture gradient measurements taken from 16 wells drilled in seven geological prospects covering more than 200 sq mi. The excellent results obtained from the developed model establish a new simple mechanism for fracture gradient prediction that is based on readily obtainable parameters. The proposed neural network model predicts the fracture gradient as a function of pore pressure, depth and rock density. A detailed comparison between the results predicted by this method and those predicted by other techniques is presented.

Cost-Effective Sand-Control Operations Play Key Role in Revitalizing a Mature Gas Field

Summary When revitalizing mature oil or gas fields, the ability to maximizeproductivity while minimizing operating costs is critical. Achieving thesegoals becomes more challenging where sand control is required. This isespecially true in connection with a complex reservoir lithology, which leadsto a variety of fracture and pore pressure gradients and premature waterbreakthrough. In addition, reduced deliverability resulting from pressuredepletion presents additional complications related to achieving acceptableproject economics. The Barbara field, located in the central Adriatic Sea, is an example ofthis type of reservoir. For this project, a dedicated work team wasassigned to identify and implement the solutions to improve field performancethrough continuous operations optimization. The Barbara field consists ofstacked pay sections that have been depleted since the early 1980s. Toachieve favorable economics, techniques had to be used that would do both:maximize the deliverability of each well and minimize operational costs. This paper reviews the Barbara field workover program. The evolution oftechniques, equipment, and products leading to enhanced productivity whilesubstantially reducing costs is described. The fluid systems and operationprocedures designed to optimize frac-pack geometry are discussed. Inaddition, the one-trip multizone gravel-pack assemblies are described thatallow multiple zones to be individually fracture packed in a single run, thusproviding significant rig-time reductions without sacrificing completionefficiency. Finally, the complex nature of this reservoir dictates theneed for a variety of completion techniques. This means that fracturepacking was not necessarily an option for all zones. For the intervals atwhich fracturing was not employed, productivity still needed to bemaximized. To accomplish this goal, perforation tunnel-cleanup procedureshave been optimized.

The Value of Cement Innovation: Reduced Cycle Time Saves Money

Summary Lightweight, low-compressive-strength cement slurries save Appalachian basin operators thousands of U.S. dollars per well when compared with two-stage cement jobs using a packer-collar tool. The average amount of annular fill-up that is required in the typical southern West Virginia Devonian shale well is 3,000 ft. Because the shale is naturally fractured and has a low fracture gradient of 0.3-0.4 psi/ft, many operators opt to cement the air-drilled, unconventional gas wells with a 12-ppg lightweight silicate cement. Over the past 5 years, more than 800 wells have been cemented with water-extended cement slurry, pumped at 12 ppg. Interestingly, the cement's compressive strength in 72 hours measures only 500-700 psi, not nearly enough to be "seen" with the cement-bond logging tools most commonly employed. In fact, at least one operator waits a full 7 days before running a variable-density log because that is about the time needed for the cement to develop enough compressive strength and acoustical impedance to be seen. While solving one problem related to cutting authorized-for-expenditures well costs, the lightweight cement caused another problem: lost production days because of waiting on cement (WOC). Using knowledge of available Portland cements and a proprietary compressive-strength enhancing agent, a new cement blend was developed that could get higher strengths and better acoustical impedance. This paper will document how one large northeast operator successfully solved the problem of cycle-time reduction while maintaining the cement density at 12 ppg. Key aspects related to the solution, including laboratory testing of the cement and cement additives and examples of post-solution cement-bond logs, will be shown. Economics related to lost days of production over a 100-well drilling program will also be discussed.

Safe Operating Window: Wellbore Stability Is More Than Just Fluid Density

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94732, "Integrated Management of the Safe Operating Window: Wellbore Stability Is More Than Just Fluid Density," by T. Hemphill, SPE, Halliburton Baroid, prepared for the 2005 SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janeiro, 20-23 June. The drilling of challenging wells, especially those in deepwater, high-pressure/high-temperature, and extended-reach environments, often is characterized by a narrow safe-operations window between formation pore pressure and fracture gradient. Overstepping the window bounds can lead to unwanted incidents of lost well control and/or lost circulation. Maintenance of wellbore stability (WBS) while drilling is critical to the success of today’s challenging wells, yet applications of such modeling have largely centered only on predictions of surface drilling-fluid density requirements. An integrated approach demonstrated the use of incorporating drilling-fluid hydraulics and barite-sag potential in the wellbore-construction process to help avoid unwanted surprises that can lead to unstable wellbores while drilling in technically challenging environments. Introduction Recently, for an extended-reach-drilling (ERD) well in the North Sea, hole cleaning and hydraulics optimization were combined with wellbore-stability modeling to produce a more comprehensive analysis of a large-diameter interval to be drilled with water-based drilling fluid. In that study, a fully coupled wellbore-stability analysis was used to estimate the minimum drilling-fluid density to prevent shear collapse and the maximum density to prevent formation fracturing during initial stages of the drilling operation. Changes in key drilling parameters such as pump rate, drillstring rotation speed, and rate of penetration were made in a “what if” fashion to determine their relative effects on wellbore stability. Following the optimization process developed for drilling the well on paper, the large-diameter hole was drilled, and the casing was cemented successfully. In the subsequent 12¼-in. tangent interval, drilled with low-toxicity mineral-oil-based mud (LTMOBM), the hole was drilled without problems, but hole instability occurred once drilling operations ceased. The hydraulics used in the actual drilling process near the bottom of the 12¼-in. interval was entered into the wellbore-stability model to re-evaluate the effects of drilling operations on wellbore stability. In this second study, a chemoporoelastic model accounting for chemical interaction between the drilling fluid and the formation, as well as full coupling between the change in pore pressure and effective stresses, was used.

Overview: Offshore Completions (August 2005)

Last year, in this space, I commented on innovations being implemented on recent offshore completion projects and how offshore completion practices have undergone major changes. Our industry, regarding offshore developments, apparently has an unlimited ability to amaze the world with new advances. Projects that were considered not feasible 5 years ago now are being implemented. Driven by various reasons, including depletion of conventional reserves and increasing oil prices, oil and gas production in deep water became customary in many regions around the world, and it was not a surprise that, during the 2005 Offshore Technology Conference, oil companies started to reveal plans aiming at production of fields under 3000 m of water. Use of intelligent-well completions is spreading globally, not only for large deepwater projects, but also for small offshore discoveries where its use in subsea satellite wells may bring profitability to an otherwise uneconomical project. Smart systems, with remotely operated valves, allow operators to control various producing zones, shutting down those not responding as expected without expensive well interventions. All of that can be achieved while data for each independent zone are simultaneously acquired and recorded. Developing fields that present complex geology and deep reservoirs that have high pressures and temperatures still present challenges for the industry, mainly when unconventional-trajectory wells are used. Some of the issues being investigated involve completion of long horizontal sections in unconsolidated reservoirs; flow assurance, mainly for deepwater conditions; and subsea processing, including gas compression and gas/liquid and oil/water separation. Some of these challenges are addressed well in the papers featured in this issue. Available from the SPE eLibrary: www.spe.org SPE 90552 - “Gravel Packing Deepwater Long Horizontal Wells Under Low Fracture Gradient,” by Chen, Zhongming, SPE, BJ Services, et al. Available from the OTC Library: www.otcnet.org OTC 17399 - “Subsea Gas Compression—Challenges and Solutions,” by Fantoft, R., FMC Kongsberg Subsea A/S OTC 17397 - “Hybrid Riser Towers From an Operator’s Perspective,” by Sworn, A., BP plc

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.

The Use of Lightweight Cement Slurries and Downhole Chokes on Air-Drilled Wells

Summary The success of a primary cement job is often measured according to effective zonal isolation, achieving the designed top of cement, and avoidance of remedial cementing. In the San Juan and Rio Arriba counties of New Mexico, many Mesa Verde and Dakota wells are air-drilled because the Mesa Verde formation is subnormally pressured and naturally fractured. This combination makes the Mesa Verde easy to hydraulically fracture during normal drilling and cementing operations. Therefore, meeting the primary-cement-job success criteria is particularly challenging. Cementing of casing within an air-drilled wellbore allows the slurry to free fall. Cement free fall can cause severe surge pressures at the bottom of the hole, leading to hydraulic fracture initiation and loss of lift. Theuse of a downhole choke (DHC) can be employed to prevent these processes from occurring. Because mud filter cake does not exist in an air-drilled hole, the lead water spacer and cement must wet the casing and wellbore rock surfaces. Loss of the lead water spacer, in conjunction with cement water loss, can produce dehydration of the cement column, leading to an increase incement viscosity and equivalent circulating density. Careful control of cement-free water and fluid loss are required to prevent this from occurring. Further more, placing cement across targeted completion intervals that have low fracture gradients requires the use of ahigh-compressive-strength, low-density cement that is competent and capable of maintaining zonal isolation during the completion and production phases of well construction. This paper will outline the evolution of the cementing practices used forthe Mesa Verde and Dakota wells drilled in the 29-6 Unit (T29N−R6W, New Mexico) from 1998 to 2002. It will illustrate how cementing changes enabled the primary cementing to be successfully completed in a single stage instead of two, which has translated into cost savings for both the drilling and completion phases of a well. The impact of using a DHC for the pumping and placement of these primary cement jobs will be illustrated and discussed. The function of the cement additives on slurry properties will also be discussed as they pertain to these cement jobs.

Gravel Packing Deepwater Long Horizontal Wells Under Low Fracture Gradient

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90552, "Gravel Packing Deepwater Long Horizontal Wells Under Low Fracture Gradient," by Zhongming Chen, SPE, Rudolf J. Novotny, SPE, Rodrigo Farias, SPE, and Alfredo Mendez, SPE, BJ Services, and Carlos A. Pedroso and Lucia Helena C. Fernandes, SPE, Petrobras, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.

新地層破砕勾配増強スクイズ法による坑井圧抑制力の増大

This paper presents the analysis methods and modeling results from a post-well study of a lost circulation/flow event in a challenging high-pressure/high-temperature (HPHT) exploration well. The effects of well conditions such as wellbore pressure changes, rock mechanical properties, and geo-pressures are reported. Results from a new lost-circulation, finite element analysis (FEA) model also help explain why various formation-sealing treatment systems (some conventional and others new) failed to reduce the losses into the loss zones. After a new fracture gradient (FG) enhancement squeeze system (FGESS) was implemented, it effectively halted the losses. Full circulation was then re-established to stabilize the well. The well had been losing at an equivalent circulating density (ECD) of 1, 965kg/m3.Application of the FGESS treatment increased the wellbore pressure containment integrity tosustain an equivalent of 2, 037kg/m3 mud as measured by a formation integrity test (FIT). This remarkable improvement in the apparent or near-wellbore FG (NWFG) or fracture re-initiation pressure (FRIP) was achieved along with several other cost-saving factors. A new FEA model is also discussed to help show how the FRIP or NWFG was increased by the FGESS treatment and may predict how FGESS treatments can increase the FRIP or NWFG in future wells. This fully 3-D model uses various types of treatment data and well conditions such as wireline log data for formation stresses and rock properties to calculate a FGESS treatment's higher FRIP or NWFG. Upon re-entry of the well 7 months after the successful FGESS treatment, the seal in the loss zones was still holding against HPHT conditions. This sustained seal reduced costs even more and allowed a liner to be set successfully without drilling fluid or cement losses in the reservoir section of the well. The conclusions of the study can help optimize well plans for future wells in the area, which can lead to lower costs for drilling fluids, casing design, cementing, and completion equipment.

Variation in vertical stress in the Baram Basin, Brunei: tectonic and geomechanical implications

The vertical or lithostatic stress is an important factor in tectonic and geomechanical studies and is commonly used in the prediction of pore pressures and fracture gradients. However, the vertical stress is not always calculated in situ and the approximation of 1.0 psi/ft (22.63 MPa/km) is often used for the vertical stress gradient. Vertical stress has been determined in 24 fields in the Baram Basin, Brunei, using density log and checkshot velocity survey data. The Baram Basin shows a variation in vertical stress gradient between 18.3 and 24.3 MPa/km at 1500 m depth below the surface. This variation has a significant effect on in situ stress related issues in field development such as wellbore stability and fracture stimulation. The variation is caused by a bulk rock density change of 2.48–2.07 g/cm 3 from the hinterland of the delta to its front. Differential uplift and erosion of the delta hinterland and undercompaction associated with overpressure are the interpreted causes of the density and hence vertical stress variation.

大水深セメンチング技術

More and more drilling occurs in frontier areas and particularly in deep water. In this environment, where the water depth often ranges between 1000 and 3000 m, the temperature at the seabed is extremely low, reaching 1 degC. In addition, a nonlinear temperature gradient in this water column and the sea currents further participate in and accelerate the cooling of the fluids in the wells. These low temperatures considerably slow cement hydration, which adversely affects the compressive strength development of the cement slurries.The young, soft formations encountered in the first few thousand meters below the seafloor preclude the use of normal-density cement slurries. However, conventional low density cements take a long time to set and develop significant strength at these very low temperatures. The daily rate of the rigs able to drill these deepwater wells is fairly high. In addition, the latest generation of offshore deepwater rigs is designed to work faster and deliver wells drilled more efficiently. It is therefore important to have lightweight cement systems that set quickly and develop high strength in the short period of time compatible with the operation of these new rigs.Often, the permeable layers below the seabed contain either free gas, when the water depth (and pressure) is reasonable, or gas hydrates at greater water depth. The lightweight cement system used in deepwater wells must therefore also control gas during its setting process at these low prevailing temperatures.This paper will address the selection of proper deepwater cement slurry. Several case histories are also presented, where lightweight cements capable of setting quickly and managing gas flow in low temperatures have been required to economically drill and case formations with low fracture gradient in deepwater wells.