Recovery of frac-pack fluids is often poor in offshore operations. Large amounts of stimulation fluids left in the fracture may leak-off into the porous formation or block part of the proppant pack thus impairing hydrocarbon production. A typical frac-pack treatment fluid contains water-wetting surfactants to maximize flow-back fluids. However, the amounts recovered are still low and new methods are needed to improve well cleanup. Using a proppant that is neither oil nor water wet has the potential to solve some of these issues. Proppant surfaces were permanently modified to a neutral wettability state. Molecules having both hydrophobic and oleophobic properties were covalently bonded to the oxide surfaces, leading to robust engineered interfaces with low surface energy thus potentially improving flow. To support this concept of neutral wettability proppant, laboratory studies were conducted to determine performance under flow and cleanup ability compared to native proppant surfaces. This neutral wettability proppant was also used in several completions in the Gulf of Mexico. Two case histories using the neutral wettability proppant are presented and compared with offset wells as well as performance laboratory data. Flowback data as well as production data are reported. Laboratory results showed that the neutral wettability enhanced surfaces not only reduce water saturation but also improve oil movement. This demonstrates the ability of these materials to improve clean up and hydrocarbon flow within the proppant pack. When this proppant was applied in frac-pack completions it was observed that flow-back recovery was dramatically increased compared to offset wells that used similar proppant. Cleanup time was reduced allowing first oil to appear more rapidly. Furthermore, production data show that oil flow that the productivity index is higher when the surface of the proppant is neutral. These results demonstrate this material as next generation proppant for improving flow and cleanup in frac-pack completions.
It has been observed that pumping a mini-frac prior to a TSO Frac-pack can impact the effectiveness of the frac-pack. The calculated fluid loss parameters determined in the diagnostic test are often not valid for the main fracture design due to the residual effect of the mini-frac and/or step-rate fluids. A technique will be presented in this paper which allows the calculated fluid loss parameters from the diagnostic test to be used reliably without excessive waiting time for the reservoir to recover to its original leak off characteristics. Fifty plus treatments were evaluated to develop a technique which makes this possible. The use of this technique resulted in a significant change in the success of the TSO designed treatments - success being a TSO type pressure increase while pumping. The success rate to achieve designed TSO, by incorporating the changes described in the paper, was increased over 20 percent with a reduction in time between diagnostic tests and the main frac. In the wells associated with this paper, a borate-crosslinked fluid was used for a mini-frac treatment followed by a step-rate test prior to the main proppant laden frac-pack. The fluid was designed with minimal polymer loading for the well conditions. The resulting mini-frac tests had low fluid efficiencies. It was originally thought that using this fluid, followed by injection of a linear step-rate fluid, would minimize the changes observed in fluid efficiency between the diagnostic test and the main fracture treatment. However, the effect of the diagnostic test on fluid leak off still resulted in less than desired TSO predictability. A technique of adding a pH control additive into the final portion of the step-rate test fluid was found to successfully allow the use of the observed diagnostic test results, honoring the efficiency from the mini-frac test. The quantity and placement of the pH control agent in the step-rate protocol were dependent upon well conditions. The waiting time between the diagnostic test and the main treatment was reduced since a positive, controlled change was applied. The optimum pH reduction for the desired effect was determined in the laboratory and designed into each treatment depending upon well conditions.
Foam diversion has industry recognition as a proven approach to diversion in remedial sandstone acidizing in deep-water environments. With long intervals and large displacement volumes it is critical that a stable diverter reach the perforations with sufficient viscosity to sustain diversion effectiveness. Industry publications and laboratory testing indicate that non-stabilized foam systems tend to breakdown over time. A novel sandstone acidizing diverter (SSAD) system was recently developed and applied successfully in the field. The new SSAD system is comprised of a surfactant based gelling agent prepared in an ammonium chloride base fluid. The formulation of the SSAD system can be altered as needed to obtain desired rheology and break profile. In order to demonstrate the viscosity potential of this system, formulations without breaker were prepared in the laboratory for each specific well application at bottom-hole temperature. For instance, a formulation designed for 240 °F bottom-hole temperature, provided a stable viscosity slug of 300 cp at 100s-1 for six hour duration. The system maintained viscosity above 100 cp at 40s-1 after six hours with internal breaker. In 2015, two wells in deep water Gulf of Mexico with 200°F bottom-hole temperatures and an average perforated interval of 114 ft were treated with an organic mud acid treatment with no diverter. These zones were then re-stimulated in late 2016 with the same organic mud acid system and the new SSAD system. The initial production of the two wells treated in 2015 versus the re-stimulation treatment in 2016 showed a twofold production increase. Diversion pressure response was observed to be as high as 285 psi. The SSAD system can be applied in wells with low and elevated bottomhole temperatures up to 300°F. The SSAD system is non-damaging to the formation and will break in presence of hydrocarbons, or an internal breaker can be added for enhanced clean-up. Other features include extended fluid stability and no additional mixing equipment or personnel requirements compared to foam. The case study of the two wells in deep water Gulf of Mexico demonstrates the effectiveness of the new SSAD treatment compared to the conventional treatments without diversion being previously pumped in the Gulf of Mexico. Not only do SSAD treatments provide enhanced diversion compared to foam, on average, the cost of an SSAD system is 25% less than a treatment using foam diversion.
Conventional asphaltene inhibitor treatments prevent asphaltene deposition in the production string and near the wellbore. However, these liquid injection treatments provide little to no protection deep into the reservoir. A new proppant like slow release asphaltene additive that is mixed with the proppant provides the possibility for long term flow assurance without conductivity impairments. This substrate allows more chemical to be transferred bottomhole resulting in longer treatments. Traditional and nontraditional screening methods were used to demonstrate the longevity of the intermediate strength proppant like slow release asphaltene additive. The additive release profile was evaluated in a mixture with proppant and using untreated crude oil. Long-term protection was then determined. Furthermore, the proppant like substrate was characterized for its proppant like characteristics using API standards. Conductivity studies, to ensure the additive did not affect the proppant pack negatively, and fracturing fluid compatibility were also performed. The results show that the proppant like slow release asphaltene additive has no conductivity losses at increased loadings and can provide a cost effective long-term flow assurance solution and can be used in the same range than an intermediate strength (ISP) proppant. Significant numbers of Gulf of Mexico (GoM) wells experience closure stresses in the range for the ISP product, opening up the possibility of using this product in this stress regime. Presence of asphaltene inhibitor in the deepest part of the fracture allows release of the chemical and resulting in reduction of precipitates and lowered conductivity damage to plugging. Controlled release of the chemical from the ISP like substrate allows only a certain amount of chemical needed for inhibitor control, preserving the rest of the inhibitor for subsequent release. The incorporation of a delay mechanism in the slow release asphaltene additive will provide increased protection as the well ages. This method allows longer protection time and affords a more cost-effective treatment.
The objective of this study is to introduce a new neutral wettability proppant that improves flow and cleanup of the proppant pack. It is known that the proppant pack permeability is the primary factor that affects the productivity of a fractured well. In such operations, fracturing fluid (cross-linked or linear) is used to deposit the proppant. In order to transport proppant within the fracture, fracturing fluid rheological properties must be attained based on fracture type, job design metrics, formation characteristics, proppant properties and proppant loading. These fluid properties are typically adjusted by using gelling agents and other chemical additives to ensure transport capability. The types and concentration of gelling agents, cross-linkers, and breakers, are known to affect the permeability of the pack. If these fluids are not removed, they build up in the proppant pack. This fluid retention leads to decreased permeability and reduced effective half-length of the fracture. In this paper a neutral wettability proppant that is neither oil wet nor water wet was used to (1) eliminate capillary pressure within the proppant pack and (2) alter the interaction between aqueous/organic (hydrocarbons) and the proppant surfaces by decreasing the intra-molecular interactions between the fluids and the proppant surfaces thus resulting in improved flow compared to native surfaces. Light weight ceramic proppant was permanently surface modified to a neutral wettability state. This new proppant was evaluated in the laboratory and in the field for compatibility with the fracturing fluid, clean-up properties through the proppant pack and recorded flow back of treatment fluids after a frac-pack operation. Results indicated that the new proppant surfaces not only reduced water saturation but also improved oil mobility. These observations showed the promises of permanently modifying surfaces as next-generation products for improved flow and decreasing the risk of formation damage due to the fracturing fluids left behind after treatment. When this proppant was applied in a frac-pack completion, flow back was efficient with rapid recovery of all pumped fluids. In this case the surface of the proppant reduced the intra-molecular forces between the proppant and the fracturing fluid, eliminating capillary pressure within the frac-pack and leading to a more efficient and quicker fracturing fluid flow back compared to using proppant in its native state. First oil breakthrough was earlier than other wells in the same area.
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