There are a number of sandstone reservoirs in which more than 50% of the matrix is composed of clay and feldspar minerals. Typically, these reservoirs are subject to fines migration and respond poorly to conventional matrix acid stimulation treatments. There are numerous challenges when treating these formations: the removal and/or stabilization of the mobile fines in the pore spaces without destabilizing the clays in the matrix or the matrix itself; the need to stimulate the formation some distance away from the wellbore, and, equally importantly, to minimize reaction products precipitating in the matrix; and the very low critical velocities that can lead to plugging while injecting the treatment. In many conventional acid treatments, after an initially good response to the treatment, the production falls to levels similar to or lower than before the treatment. A common compromise is to empirically adjust the strength of a HF/HCl acid system used to treat a particular formation, so as to delay the onset of renewed fines migration after the treatment for as long as possible, at the expense of optimizing productivity. In many cases this results in making the treatments uneconomic.To meet theses challenges a new fluoroboric acid system has been developed. The basic chemistry used is similar to that of a retarded HF acid previously described in the literature as clay acid (Thomas and Crowe 1978). . However, unlike the retarded HF acid, the new fluid uses organic acid as a chelant and is effectively a blend of organic/fluoroboric acid and hence an organic clay acid. The fluoroboric acid is generated by the addition of hydrofluoric and boric acid. By adjusting the initial concentration and ratio of hydrofluoric and boric acid, it is possible to optimize the stimulation effect of the treatment in a particular formation and prevent future fines migration. A key is the initial concentration of free hydrofluoric acid and the available hydrofluoric acid from hydrolysis of the fluoroboric acid with respect to the clay mineralogy and temperature. The concentration of the organic acid, the chelant, is also adjusted based on an analysis of the effluent during core flow testing, to minimize precipitation.Prior to customizing the organic clay acid system, treatments were performed in low temperature (< 140 o F) reservoirs, with 30% kaolinite along with zeolite and chlorite present in the formation matrix. While there was a noted stimulation effect and fines stabilization, the initial post-treatment productivity fell short of that seen using an organic mud acid. In the case of organic mud acid, however, the production declined rapidly, indicating renewed fines migration. This led to a reformulation of the organic clay acid for use as the main treating fluid, eliminating the need for HF preflushes. The initial productivity of wells treated using the reformulated organic clay acid were higher than that obtained using an organic mud acid and remained stable, indicating effective fines migration control.In contrast to what might be e...

A brownfield in Colombia, produces from the Caballos formation, a highly laminated sandstone formation with permeability of 50 to100 md. The field is under water injection, resulting in calcium carbonate scaling; thus, these wells need to be acidized routinely although the water cut often exceeds 90%. Initially, straddle packers were used to divert the treatments mechanically across the laminated sands, which required a workover rig. To reduce the cost of treating these wells, recent treatments were bullheaded down the tubing casing annulus at the highest possible matrix rates, resulting in mixed results. Water cut increased with no or an insignificant increase in oil production. Hence, a diversion technique/fluid was needed that would provide effective zonal coverage similar to that obtained using straddle packers. The viscous disproportionate permeability modifier (VDPM) fluid was developed for this application. The initial treatments, performed by pumping alternate stages of acid and a VDPM fluid, increased oil production as much as 300% while reducing the water cut by up to 10%. In these cases, the increase in production is equal to or better than wells treated selectively with straddle packers. The use of a VDPM fluid has been shown to be capable of improving zonal coverage, increasing oil production, and decreasing water cut in formations without natural fractures or fissures. During the treatment, the treating pressure increases or remains constant while, in core flow tests, the pressure increases sequentially when injecting acid after each stage of diverter. Despite this, the final effective permeability to oil increases and the effective permeability to water decreases significantly. The VDPM fluid reduces the effective permeability to water up to 80% in a water-saturated core. In the field, the permeability and the length of the interval(s) to be treated determine the number, volume, and viscosity of the VDPM fluid stages based on previous core flow studies. The use of the VDPM fluid has the potential to increase the economic viability of producing this particular field in Colombia and other similar fields. The properties of the VDPM fluid are particularly advantageous when repeatedly treating wells in mature fields on water injection.

The ultra-high pressure and temperature (HPHT) lower Cretaceous sand-shale layer in Krishna-Godavari basin (KG basin) (Fig. 1), in eastern India offshore shallow water, in the Godavari River interdeltaic region, is currently the world's highest-temperature petroleum reservoir being explored in the marine environment. It is a part of the fluvial sedimentary KG basin, which is recognized as holding India's largest gas reserves. Its area is approximately 50,000 km 2 and it extends from land to the shelf-slope and adjacent deep-sea area along the eastern passive continental margin of India. The bottomhole static temperature of the reservoir ranges from 350 to 450°F at 16,000 to 18,000 ft true vertical depth (TVD), with pore pressure gradient up to 0.85 psi/ft. The hydraulic propped fracturing technique is integral to the completion and well testing program in this typical tight reservoir.The design and delivery of hydraulic propped fracturing in such a complex reservoir and operational environment requires advanced technologies and meticulous planning and execution, including reservoir and geomechanical characterization derived from latest HPHT formation evaluation logging tools, implementation of integrated production simulation and fracturing modeling software, and application of ultra-HT completion and fracturing products. In addition to technical complexity, the limited drilling unit capability also required equipment planning that involved an integrated fracturing and testing wellheadstring-packer system, a project-specific modular HPHT stimulation boat and post-fracture flowback testing plan and equipment that included surface well testing and a coiled tubing nitrogen fleet.Several successful hydraulic fracturing operations were performed in this tight ultra-HPHT reservoir for multiple operators. This paper will describe the case history of the hydraulic fracturing completion campaign for one operator in the basin, in particular describing ultra-HPHT techniques and products that were key to the project delivery:• Basin modeling, reservoir, and geomechanical characterization workflow as an integral part of hydraulic fracturing design in complex frontier reservoir • Installation and preparation of modular HP/HT stimulation vessel custom built for this project • Implementation of synthetic fracturing fluids developed specifically for ultra-HT application up to 450°F in a high-pressure and high-shear environment.