Stimulation-design considerations usually include things like formation-fracture gradient, reservoir pressure, stress, casing size, perforation schemes, etc. The type of cement that fills the annular space between the openhole lateral and the casing is not typically considered with regards to its impact on the execution of the frac treatment.Early horizontal-well completions observed much higher injection pressures than those observed in vertical wellbores in the same formation. Research identified the effects caused by transverse, oblique, or longitudinal fractures from horizontal wellbores, which were usually nonissues in vertical completions. Near-wellbore (NWB) friction (tortuosity) is a component that is common to both vertical and horizontal wellbores but seems to be ignored in horizontal completions. When proppant cannot be placed during a horizontal frac, it is usually blamed on formation-fracture width (or lack of it) and proppant size (mesh size is too large). These are the typical reasons used to explain early screenouts and have become commonplace in the industry. The authors of this paper believe NWB tortuosity issues have a much larger impact than most think and will show how a properly engineered production casing cement, in conjunction with the stimulation design, allows the placement of large-mesh proppant at high concentrations in the Eagle Ford shale. High conductivity is essential for maintaining liquid-rich production.Fracture initiation in a horizontal well, especially at the toe, can sometimes be very difficult. To minimize injection issues, acid-soluble cement (ASC) was placed in the lateral of several Eagle Ford-shale wells in Karnes County, Texas. Hybrid stimulation treatments were used to place 20/40-mesh proppant at concentrations up to 4 lbm/gal, most without issue. Proper engineering was used to successfully fracture stimulate all the intended intervals (including the first stage at the toe).Utilization of ASC for horizontal completions can help improve stimulation efficiency and allow alternate onsite frac options that can turn an otherwise-abandoned completion interval into a successfully stimulated section of the reservoir.

Well cementing operations in south Texas tend to present a number of challenges to those responsible for constructing oil and gas wells. For instance, the temperatures and pressures at which the cement needs to be placed can be extreme, routinely exceeding bottomhole static temperatures of 300°F and pore pressures requiring fluid densities of 17 lbm/gal or greater to maintain well control. These extreme conditions can present challenges not only during placement of the cement slurry in the wellbore, but also later to the set cement sheath during the life of the well.To effectively meet these challenges, well operators in south Texas have been using high-density cements that have been mechanically modified so the set cement will be more elastic and resilient. Advanced diagnostic software is used to predict well situations where these cements are required.Currently, high-density elastic cements (HDEC) have been placed in more than 40 wells in southern Texas and the use of these sealants combined with diagnostic software has become routine.This paper discusses the challenges presented when cementing high-temperature, high-pressure (HTHP) wells in south Texas, then details the successful best practice life-of-the-well solutions that have been applied by highlighting two representative examples.The purpose of this paper is to help assist those tasked with the construction of HTHP wells to achieve their objectives safely and reliably and deliver zonal isolation that can be expected to last for the life of the well.

Horizontal wells can present special challenges for cementing operations. Extended-reach lateral sections, unconventional mineralogy, and high-pressure/high-temperature (HP/HT) environments can cause failures during and after the cement job. The high clay content and ductility of these formations force operators to use oil-based mud (OBM) to drill the curve and lateral section. A narrow pore-pressure/fracture-gradient window and tight annular clearance create higher than usual equivalent circulating densities (ECDs) and can affect mud displacement efficiency and cement placement. As unconventional reservoirs become more prevalent, increased focus on the cementing process will be vital to the long-term success of the well. New theories and proper planning will help decrease the probability of an irregular cement job and increase the chances of having zonal isolation for the life of the well. In this paper, many aspects of the cement job design are discussed and recommendations are provided for horizontal cementing in unconventional reservoirs. New testing methods and additive composition help ensure the compatibility and thermal stability of the cementing fluids while creating more realistic wellbore hydraulic modeling and job optimization. Improved casing attachments and plug sets help increase displacement efficiency, while formation-specific cement designs increase effectiveness of the stimulation method. As multistage sliding-sleeves completion tools become more prevalent and increase efficiency, the cementing operation should align with the overall goal of the completion procedure. With the entire lateral section in one formation, it is not only critical to isolate the target formation from shallower zones but to also create a good annular seal between fracture stages. Without isolation, communication between stages can cause fracture treatments to migrate to unwanted areas. Modeling the expected temperatures, forces on the formation, displacement efficiency, and stress on the set cement sheath allows for a design that meets the expectations during the life cycle of the well. Complex temperature profiles create unfavorable design criteria, so accurate temperature determination is an important element to the cement design. With a renewed focus on the fundamentals of cementing, sufficient planning, and new technology, these unconventional reservoirs can become a manageable and sustainable resource for many years.

Successful liner cementing in unconventional shale wells is strongly dependent on slurry stability. A delayed-release, high-temperature suspending agent was developed that provides viscosification and stabilization of the slurry without causing excessive viscosification and mixing problems at the wellsite. The suspending aid was prepared from water-soluble, thermally stable monomers copolymerized with degradable crosslinking monomers. The crosslinks degrade as the temperature of the slurry increases, ultimately resulting in dissolution of the polymer and concomitant slurry viscosification. The performance of the suspending aid was demonstrated by means of laboratory testing under typical Eagle Ford shale conditions. Improvements were observed in terms of fluid-loss control (54 cc/30 min [control] to 28 cc/30 min), free fluid (5% [control] to 0%), sedimentation (Δρ 5.2 lbm/gal [control] to Δρ 0.2 lbm/gal), and consistometer off/on tests. Three field examples from the Eagle Ford are presented where the suspending aid was used to establish the desired mud-spacer-cement rheological hierarchy at bottomhole circulating temperature (BHCT); provide sufficient slurry stability to set the liner top plug, circulate out excess cement, and produce a competent cement sheath; and improve the mixability and stability of a barite-weighted spacer.