No abstract

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.

Many wells in the Cana-Woodford shale suffer from chronic sustained casing pressure (SCP). With more stringent SCP regulations on the horizon, operators need a way to prevent SCP effectively during primary cementing because remediation can prove costly or detrimental to business. At the start of a recent project virtually all cement bond logs showed poor coverage and a lack of zonal isolation. Due to the poor cement sheath bonding, SCP was occasionally observed before fracturing and almost always occurred after fracturing. This paper discusses a method that has resulted in a high success rate in preventing SCPwhere previously, failure was common.An integrated approach between multiple service company operations and operator was used to address the cement bonding issues and the long-term integrity of the cement sheath. The ultimate objective was to not have any SCP on any annulus of the well for the lifetime of the well. Initially, high-resolution ultrasonic bond logs were run to evaluate slurry placement and methodologies. Placement of the slurry around the casing was then optimized using laboratory testing and modeling software based on lessons learned from log evaluation. The success of the engineered approach was evaluated with ultrasonic logs utilizing flexural attenuation, thereby validating simulations. Finally, the long-term set cement properties were evaluated through the use of stress analysis software, which simulated stimulation treatments and their effect upon the mechanical properties testing.Cement placement was optimized with an oil-based mud (OBM) recovery in mind. Using simulation software, centralization of the production casing was evaluated, and an optimized frictional pressure hierarchy then designed. A cement bond log was run to evaluate the proposed solution. The results proved that zonal isolation was achieved throughout the curve and into the casing-to-casing section. The logs showed excellent coverage in this well relative to its peers and the best results to date. Continued monitoring showed no casing pressure after stimulation and 1.5 years of production. The operator's other seven wells in this section, which did not have the engineered approach applied, showed SCP immediately after stimulation.The engineered placement method ensured complete cement coverage around casing through an optimized frictional pressure hierarchy. This multilayered approach using mechanically optimized slurries with different mechanisms of action, including self-healing, provided a comprehensive cementing portfolio that contained layers of contingency. To date, the method has a high success rate in the prevention of SCP in the Cana-Woodford shale. Unconventional gas/liquid plays have changed our industry. The methodology outlined in this paper has been successful, and the lessons learned can be applied to many other unconventional gas/liquid plays that include fracturing stimulation for development.

Since the 1970s, 12 deep vertical gas wells in the Thomasville area in Mississippi, USA have been producing high volumes of sour gas (3 to 21 MMcf/D per well). This production decreased to unsustainable levels, which required the field to be abandoned. Abandonment presented a rare combination of challenges including high temperature (>400°F), high sour gas and CO2 (more than 40% H2S and up to 9% CO2), depleted formation (0.1 psi/ft), scale buildup, unique well geometry, true vertical depth ranging from 20,300 ft to 23,600 ft, and nearby residential areas. A combination of special operating procedures, intelligent self-healing cementing slurries, and novel placement techniques enabled the wells to be successfully abandoned with layers of contingency to prevent a catastrophic environmental release. The plug and abandon operations were divided into two phases. Phase 1 was rig-less operations to kill the well and isolate the formation by using an engineered ultralightweight 9.0-lbm/gal cement slurry that provides greater corrosion protection compared to a normal cement slurry. Novel placement techniques were used to place the engineered slurry across the production perforations and open hole to isolate both the tubulars and annuli. Advanced hydraulic simulations were run to model the complex placement. A traditional drilling rig was moved in for phase 2 of the operations. In phase 2, intelligent cement plugs, which included flexible and self-healing properties, were placed to add greater zonal isolation assurance accounting for unknown well conditions for the long-term abandonment of the well. Cement plugs were verified with robust negative and positive pressure tests. It was determined that an ultralightweight slurry could be placed with a 0.1-psi/ft fracture gradient using nitrogen displacement, optimized slurry volume, and variable choke to regulate pressure on the backside to isolate the wellbore. Displacing with nitrogen proved to be challenging, and the many lessons learned will be documented in this paper. All 12 of the producing wells, along with 5 disposal wells in this field, were successfully killed and plugged. To date, none of the wells are showing pressure. This paper will review the challenges faced with designing a successful P&A program in this Thomasville area. Both phases of the final operations will be presented, and lessons learned along the way will be discussed. These complex well conditions were overcome through sound designs in operational planning, cement slurry optimization, placement techniques, and isolation testing methods. The primary plug proved to be effective at being placed in a depleted environment and at ultrahigh temperatures while taking into account corrosion protection. The intelligent cement slurry offered long-term barrier assurance through both failure prevention and self-repair. The long-term solution outlined in this paper is key to preventing a catastrophic environmental release. The innovative placement techniques, contingencies taken, and lessons learned during the campaign will be useful to other technologists in other fields faced with similar conditions.