Marcellus gas-shale trends have transformed the regional and national outlook for natural gas supply and are particularly attractive for their proximity to high demand markets and existing pipeline infrastructure. Marcellus shale plays offer unique operational and regulatory challenges during mud removal, cementing, and completion operations. Sustained casing pressure (SCP) is one of the greatest challenges encountered after completion. The Department of Environmental Protection (DEP) in Pennsylvania has enacted strict policies regulating cementing practices in Pennsylvanian Marcellus shale trends to reduce the risk of inter-zonal communication and SCP due to substandard annular cement sheath integrity. To ensure compliance with DEP cementing guidelines, a flexible, expanding cement system (FECS) was developed with fit-for-purpose mechanical properties. A further FECS blend modification included an additive to promote bulk cement expansion during hydration. Since implementation, this approach, coupled with good mud removal and cementing best practices, resulted in rapid static gel strength (SGS) development, acceptable compressive strength development and waiting on cement (WOC) time, and improved flexible and expansive properties. Since introduction in 2010, six jobs (two intermediate and four production strings) have been successfully cemented with FECS technology. A Marcellus shale trend case study will be presented in this paper that discusses the successful application of FECS during cement placement around a production casing. After completion of each job, a successful shoe test was performed. After stimulation/fracturing treatments, SCP was not reported by the client in Marcellus wells cemented with FECS. Since implementation in 2010, FECS technology has become a proven approach for cementing Marcellus horizontal tight-gas shale environments where long-term zonal isolation and minimal SCP are required. This approach has been applied to Marcellus shale and Permian Basin formations while other applications are currently being explored.

Recently discovered Haynesville gas-shale trends have transformed the regional and global outlook for natural gas supply, but offer unique challenges to the operator and service company during mud removal, cementing, and completion operations. To counter these challenges, recent advances include improved drilling, centralization, mud-removal, cementing best practices and implementing a broad particle size distribution-engineered (PSDE) cement system for use in high temperature horizontal intervals reaching across high pressure, high temperature (HPHT) gas-shale trends. For PSDE cement systems, rheological properties are based on inter-particulate interactions to achieve the desired viscosity and not based on polymeric extenders/antisettling additives. Since PSDE fluids are not dependent on polymeric thermal thinning behavior, they demonstrate consistent rheological properties over a wide temperature range and are more suitable for placement in narrow annuli.In this paper, Haynesville cement placement and extensive laboratory testing best practices will be discussed. Also, a case study will be presented that describes a typical and successful placement of PSDE cement fluid in the Haynesville shale at bottom hole circulating temperatures (BHCT) up to 182 o C [360 o F] and bottom hole pressures (BHP) up to 82.7 MPa [12,000 psi]. After successful job completion and time allowed for the cement to properly set, an annular seal pressure test was successfully completed, with minimal pressure bleed-off.Since introduction in 2009, over 390 production jobs have been successfully cemented using the PSDE cement technology, with 99.5% placement success rate. Acquired well head pressures (WHP) were less than or equal to predicted WHP for most production jobs. PSDE Cement Technology has become a proven approach for cementing high-temperature, horizontal tightgas shale environments in relatively narrow annuli where fluid stability and zonal isolation are needed during placement and subsequent hydraulic fracturing treatments. This approach has been applied to Haynesville and Eagleford shale horizontal reach production wells and is being investigated for use in other high temperature, high pressure applications.

Lost circulation, a time-consuming issue that has long plagued the oil drilling industry, presents a number of challenges to the operator such as lost rig time, stuck pipe, increased cost from lost drilling fluids, well-control situations, and bad zonal isolation due to poor cement placement. Several methods are used to treat lost circulation, depending on the severity of the losses and the type of losses. For severe losses (100 to 500 bbls/hr), few methods are routinely successful in curing losses with a treatment that is durable and lasting until the well is cemented. The methods used to treat severe losses include pills with coarse, medium, and fine particles and crosslinked polymers or gunk/cement pills. The mixed results of such methods in attempting to treat total losses in a durable way have led to the design of a fusible-particle lost-circulation material (FPLCM). This study investigates the properties and placement techniques of FPLCM through four field studies in the Elk Hills field, Bakersfield, CA.FPLCM consists of fusing particles, along with weighting agents of optimized particle size and various additives that control leak-off rate and dispersion of the material. FPLCM can also be used with engineered fiber material (EFM). The fusing of the material depends on dehydration rate, which can be controlled depending on lithology and lost-circulation geometry (highly permeable depleted sands, impermeable shale, natural or induced fractures, etc.). FPLCM works best if placed during fracture initiation and/or propagation, when the material will dehydrate both axially and radially in the fracture, thus isolating the fracture tip and increasing the nearwellbore hoop stress.Laboratory data have shown that FPLCM can plug a variety of different fracture geometries, while at the same time passing through smaller drillbit nozzle geometries. Further, FPLCM remains stable under simulated downhole temperatures for extended periods of time without gelling, but, at the same time, set rapidly under simulated fracture closure pressure.Currently, four trials have been performed in the Elk Hills field, in which FPLCM immediately promoted returns of 80% to 90% after placement in wells that previously had varying degrees of returns (0% to 70%). All treatments have been applied during drilling operations either through the bottomhole assembly (BHA) or through a fluid diverterbypass tool.

Typical organophilic clay-free invert-emulsion fluids (IEFs) are known to offer improved performance compared to conventional organophilic clay-based IEFs. However, for both the typical clay-free IEFs and conventional clay-based IEFs, high-temperature stability continues to remain a challenge from aequivalent circulating density (ECD) management and cuttings transport standpoint. This paper discusses the latest generation of clay-free IEFs, termed as "low-ECD clay-free IEFs,"that consist of specific combinations of weighting agents, colloidal particles, and polymers. The composition of these low-ECD fluids leads to different rheological behavior compared to typical clay-free IEFs, especially at high temperatures (>200°F). This paper demonstrates that the peculiar rheological behavior of the low-ECD clay-free IEFs results in superior hydraulics and sag performance. Understanding the rheology also helps effectively design these fluids. Experiments were conducted to study the rheology of several low-ECD and typical clay-free IEFs at high-pressure/high-temperature (HP/HT) conditions using rotational viscometers. Fluids were studied across a temperature range of 40 to350°F and up to 12,000-psi pressure. The data were used to develop models for predicting the rheology of various fluids as a function of temperature and pressure. Using the rheological models, hydraulics performance of the low-ECD and typical clay-free IEFs was simulated in a high-temperature well. The simulations evaluatedthe ECD and cuttings carrying capacity of these fluids. Sag behavior of the fluids in the well was also investigated. The rheological study showed that typical clay-free IEFs thin with temperature (i.e., viscosity decreases with increasing temperature). In contrast, the low-ECD clay-free IEFs showed increased viscosity with temperature (i.e., temperature thickening). Temperature thickening was especially prominent at lower viscometer rotational speeds (i.e., lower shear rates). The temperature thickening helps the fluid retain its ability to suspend cuttings, barite, and other particulates. The contrast in the rheology behavior was used to demonstrate the ultimate advantage of the low-ECD clay-free IEFs—the desired cuttings transport and sag performance in a well can be achieved at significantly lower wellbore pressures (or lower ECDs) compared to typical fluids. Wellbore case studies confirmed the accuracy of the rheology and hydraulics models for low-ECD fluids and the fluids’ superior performance at high temperatures. The low-ECD clay-free IEFs can be accurately designed to provide superior wellbore pressure management and wellbore stability. This work is crucial for narrow-margin and high-temperature wells.

Controlling severe to total lost circulation in naturally fractured vugular formations and rubble zones can be challenging. In such situations, conventional lost circulation materials (LCMs) might not be effective, and more difficult applications, such as gunks, reverse gunks, or cement, might fail as well. High fluid loss squeeze (HFLS) applications have been applied with mixed success. A new HFLS LCM containing a unique component has been developed and shows great potential as a dependable solution. This new HFLS LCM also shows potential for sealing induced fractures in shale or other formations of low permeability. This paper discusses a laboratory investigation of a HFLS LCM to plug slotted discs of various sizes in a permeability plugging apparatus (PPA) test. Follow-up field applications that demonstrate its success are also discussed. The proposed HFLS LCM is a combination of particulates and a unique reticulated foam material that contributes to a rapid dewatering effect. The reticulated foam is the unique component, which forms a bridge on the face of large fractures. The particulates of the composition then plug the foam, forming a thick cake. Recommended practices for mixing and placement of HFLS LCM essential for successful applications are also discussed. The HFLS LCM application was able to seal slotted discs up to 3000 μm. Supplementing the HFLS LCM with additional larger reticulated foam (medium) enabled the plugging of slotted discs up to 8000 μm. For plugging slotted discs from 8000 to 10 000 μm, the HFLS LCM was supplemented with medium and coarse reticulated foam. This plugging data, covering slotted disc sizes up to 10 mm, is the first of its kind and provides confidence in considering the HFLS LCM as a potential option for severe to total loss situations. Three applications of HFLS LCM are discussed. The first application manages severe losses (in the range of 180 bbl/hr) in a naturally fractured shale formation in an unconventional reservoir in North America. The second application manages severe losses in naturally fractured, vugular formations in the Asia Pacific region. In both the cases, because high losses were expected, the HFLS LCM was stored on-site as a contingency LCM. As soon as losses were observed, an appropriate volume of the pill containing the HFLS LCM supplemented with additional amounts of reticulated foam LCM was pumped. Losses were cured, and the wells were drilled/cemented successfully.