Retarded acid systems are highly sought out to allow for deep penetration of acid to improve the efficiency of acid stimulation treatments. This is important in high temperature carbonate reservoirs or in long intervals that shift injection rates away from optimum, causing near-wellbore (NWB) spending and inefficient stimulation. Acid retardation can be accomplished by viscosifying acids with polymers/gelling agents or emulsifying in diesel. However, these systems had their performance limitations and associated drawbacks. This paper presents a novel low-viscosity, single-phase, polymer-free delayed HCl acid system as an alternative for gelled and emulsified acids for stimulation of high temperature carbonate reservoirs. Novel concept of acid retardation without emulsifying the acid in diesel or gelling with linear/cross-linked polymer was introduced and evaluated. Static carbonate dissolution tests were first conducted to optimize the formulation of the new acid system to achieve the desired retardation. The retardation performance was then further evaluated using reaction kinetics measurements and coreflow testing. The diffusion coefficient of the delayed acid was measured and compared to the 15% HCl at wide temperature range (75 to 300°F). Coreflow tests were conducted on Indiana limestone cores (6 in. length and 1.5 in. diameter) with wide permeability range from 1 to 1000 md, interstitial velocity from 0.2 to 10 cm/min, and temperatures up to 300°F. The delayed acid system was also evaluated in coreflow at both 15 and 28 wt% acid strengths. Computed tomography scanning was used to characterize the wormhole dissolution pattern. At 275°F, diffusion coefficients measured from the reaction kinetics tests are 100 times lower for the delayed acid compared to HCl. Coreflow testing results showed that the delayed acid system requires significantly less acid pore volume to breakthrough compared to HCl acid at all injection rates. At low non-optimal injection rate of 0.5 ml/min and high HCl acid strength of 28 wt%, the delayed acid requires six times less acid pore volume to breakthrough compared to 28 wt% HCl and creates a dominant wormhole rather than face dissolution. In the comparison tests with the emulsified acid, the delayed acid penetrates 40% deeper in long Indiana limestone cores at 300°F. The results confirmed that the use of low viscosity delayed acid would prevent NWB spending, improve the acid penetration to access deeper reservoir area, and eventually lead to successful acid stimulation treatment even when pumping or completion limitations force low injection rate. The low viscosity, single-phase, polymer-free delayed HCl acid system showed tunable reaction rate, high dissolving power, low corrosion rates, low friction pressures, and no residue left in the formation combined with no special operational requirements. Most importantly, it provides the industry with a novel alternative fluid system to the emulsified and gelled acids.

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.

A high-strength, alumina-based solid scale inhibitor was developed for subsea applications. Laboratory elution tests show that this solid inhibitor has a nearly constant inhibitor release-rate profile in the long term. The strength of this solid inhibitor is comparable with high strength proppant, and the smallest particles generated were 135 μm as the mixture of 20 wt. %. This material was applied to four zones in two deepwater Gulf of Mexico wells. After 17 months of production, the wells were still producing inhibitor above the MEC, and the cumulated water/oil production was approximately 1.1MM bbl and 7.8MM bbl respectively.

Abstract Formation damage caused by mineral scale development is one of the major reasons resulting in reduction of hydrocarbon production during a well's life cycle. Scale inhibitors are most widely used to control scale deposition in producing wells either by adding them directly to fracturing fluids in wells where stimulation treatment is planned or by performing remedial squeeze treatments. Prolonged protection can be achieved by adding proppant-sized solid inhibitor during the stimulation treatment. The current study addresses the benefits of alternate methods of placing solid inhibitor depending on the well completion system. In the case where stimulation treatment is not planned, the solid inhibitor can be placed in the annular space between the production tubing and formation in the long open-hole horizontal well to provide extended protection as the well starts to produce. This solid inhibitor once depleted as evidenced by residual analysis can be recharged effectively by injecting liquid inhibitors that restores the effectiveness, allowing extension of protection life-times. An appropriate inhibitor chemical was first identified for the treatment from the produced water scaling analysis. A suitable solid scale inhibitor was prepared by adsorbing this chemical onto a high surface area water/oil insoluble substrate, and multiple surface modifications made to control the inhibitor release rate. The long term inhibitor chemical release profile was evaluated by packing this solid inhibitor into a column and eluting with synthetic produced water at expected bottom-hole temperatures of 200°F. The solid inhibitor elution tests show long protection times when solid inhibitor was applied. The projected inhibitor protection would be more than 60,000 pore volumes (PVs) of produced water before the inhibitor chemical was substantially depleted. In a well, 3000 pounds of this inhibitor can be potentially placed in the annular space, which would result in preventing scaling for 330 thousand barrels of water being produced, with protection life-time of more than 5 years (at 170 barrels of water per day). The presence of high surface area substrate allows inhibitor to be recharged after inhibitor depletion. The efficiency of the inhibitor recharge application was investigated by a series of column experiments. Placing the solid inhibitor into the annular space will delay the requirement for scale squeeze treatments significantly, and reduce the overall well maintenance cost for the operator, particularly in an offshore environment. The ability of the solid inhibitor to be re-charged using conventional scale squeeze chemistry enables more chemicals to be retained when subsequent squeeze is potentially performed on the wells.

Abstract Paraffin deposition, resulting in productivity loss of newly completed wells, is a major source of formation damage and is operationally and financially critical to address with a proven solution. Paraffin inhibitors included in the stimulation treatment have limited long term success due to cost and limitations on the amount of inhibitor that can be added to provide the desired longevity. A dispersion based paraffin inhibitor adsorbed on a high surface area substrate was developed which is compatible with fracturing fluids and affords a long term, cost effective solution to the paraffin deposition problem. Laboratory studies were conducted under simulated field conditions, and the effect of inhibitor on oil properties (pour point, cold finger) as the oil is treated in the proppant pack with adsorbed paraffin inhibitor was investigated. Oils with different paraffinic issues were analyzed in this study. The studies estimate the longevity of treatment and the improvement expected using this treatment for field applications using flow-through column tests. Traditional paraffin inhibitor treatments have provided limited long term performance in wells with paraffin issues. Little protection is provided beyond the perforations when continuously treating into the production fluids through capillary injectors. Additionally, squeeze treatments designed to increase the chemical's contact area by forcing the chemical treatments deeper into the reservoir give limited longevity in high paraffinic wells. In the current study, a novel treatment results in greater amounts of inhibitor placed downhole for prolonged treatment. A combination treatment was recommended whereby a compatible submicron-sized paraffin inhibitor dispersion is added to the fracturing fluid. In addition, a dispersion based paraffin inhibitor was adsorbed onto a proppant-like substrate that can be mixed into the proppant and delivered deep into the formation with fracturing or refracturing treatments, providing enhanced flow assurance management.

AbstractCalcium sulfate is inherently a difficult mineral scale during oil and gas production process because the amount of scale formed is much greater than that of barium sulfate at similar scale saturation index level, and it is very difficult to clean up. This is especially challenging in conjunction with HTHP stimulation treatments where compatibility of the scale control chemical with fracturing fluids is critical, and when longer-term inhibition performance is desired. A new solid inhibitor was developed for this purpose and applied in multiple wells in the Krishna Godavari (KG) basin offshore India to combat mineral scale within the proppant pack and production tubing over the long term, under extreme downhole conditions (T= 400°F, P=13,500 psi). Normally, downhole chemical injection mandrels and surface treatments cannot adequately control scale deposition under these conditions.The new solid inhibitor product was made by adsorbing scale inhibitor onto a high-strength, proppant-sized substrate with a large surface area. The high-strength substrate were prepared by sol-gel chemistry through hydrolysis of aluminum alkoxides and formation of particles that are calcined and then sintered at high temperatures to produce a substrate with the desired strength and surface area. The scale inhibitor used exhibited excellent inhibition performance and good compatibility with metal based cross-linked fracturing fluid systems at high temperature.Tests performed with proppants/substrates show that using high loading of the substrates with the proppant does not damage the proppant pack even under very high stresses, For example, API crush tests of a mixture of 80% conventional untra-high strength proppant with 20% substrate by weight at 13,000 psi produced less than 4.7% fines and 88% of the produced fines were larger than 100 mesh and the fracture conductivity of the pack is maintained. The results of comprehensive laboratory testing show the new solid inhibitor can prevent anhydrite scale up to 400°F, and is completely compatible with zirconium- crosslinked fracturing fluid at 350°F and above. To date, six fracture treatments have been performed using a total 23,800 lbs of this new solid inhibitor. The wellhead water samples are being collected for scale inhibitor residuals analysis, as the wells start to produce water.To ensure compatibility of the inhibitors with high-temperature fracturing fluids, especially metal based cross-linked fracturing fluids, without compromising the inhibition longevity at high pressure and temperature remains a stiff challenge, although adding scale inhibitors to a fracturing fluid has been a well-established practice to provide long-term inhibitor protection during hydrocarbon production. The new approach described here meets this objective, extending the long-term well performance under HTHP conditions.

Abstract The formation and deposition of mineral scale can detrimentally impact production rates and affect the overall well performance during oil and gas production. This is especially challenging in HTHP stimulation treatments where compatibility of the scale control chemical with fracturing fluids is critical, and longer-term inhibition performance is desired. A new solid inhibitor was developed for this purpose and applied in multiple wells in the Eastern offshore basin of India to combat mineral scale within the proppant pack and production tubing over the long term, under extreme downhole conditions (T= 400°F, P=13,500 psi). Neither downhole chemical injection mandrels nor surface treatments can adequately control scale deposition under these conditions, spurring the need for a longer-term inhibition program for these wells. A liquid scale inhibitor with excellent inhibition performance and good compatibility with various fracturing fluid systems at high temperature was first identified. The new solid inhibitor product was made by adsorbing the scale inhibitor onto a high-strength, proppant-sized substrate with a large surface area. The substrate is synthesized using nanotechnology, to prevent any possible conductivity loss under high formation closure pressure. Various chemical modifications were made to this adsorbed solid inhibitor to prevent excessive inhibitor release during early stages of production, resulting in a longer-term scale protection. This modification allows the solid inhibitor product to be completely compatible with the fracturing fluid. Scale modelling indicates that the wells treated have a severe anhydrite scale problem under downhole conditions. The results of comprehensive laboratory testing show the new solid inhibitor can prevent anhydrite scale up to 400°F, and is completely compatible with zirconium- crosslinked fracturing fluid at 350°F and above. To date, six fracture treatments have been performed by using a total 23,800 lbs of this new solid inhibitor. The wellhead water samples are being collected for scale inhibitor residuals analysis, as the wells start to produce water. The residuals data review and comparison with laboratory-derived data are discussed in this paper. Adding scale inhibitors to a fracturing fluid has been a well-established practice to provide long-term inhibitor protection during hydrocarbon production. However, to ensure compatibility of the inhibitors with high-temperature fracturing fluids, especially metal based cross-linked fracturing fluids, without compromising the inhibition longevity at high pressure and temperature remains a stiff challenge. The new approach described here meets this objective, extending the long-term well performance under HTHP conditions.

Abstract Formation damage and the resultant reduction in hydrocarbon production rates due to clay expansion are long-recognized problems (Ohen, 1991). The clay damage may occur during the drilling, completion and production phases of well operations. Often the remediation of clay damage is inadequate, providing only temporary improvements in hydrocarbon production. The prevention of clay expansion presents a challenge; fit-for-purpose chemistries exist, and are a function of clay identity and operational phase of the well. Two broad subsets of clay damage mechanisms are chemical and mechanical considerations (Bennion, 2002). The focus of this study is to evaluate the minimization of clay hydration by coating clays to prevent chemical or reactive damage. An example of chemically induced formation damage would be clay swelling. On exposure to introduced aqueous fluids, other than interstitial water, sensitive clays will hydrate detrimentally. The end result can be subsequent hydrocarbon flow restrictions due to a decrease in pore space and detrimental formation softening allowing embedment of proppant. Chemical methods of ameliorating clay expandability potential fall into two broad categories: temporary and permanent stabilizers. The temporary clay control additives prevent clay swelling by increasing the ionic strength of treatment fluids, e.g., potassium chloride. Permanent clay stabilizers create a protective sheath around the clay. The formation of a self-assembled monolayer (SAM), where the chemical covalently bonds to the siliceous formation surface, offers a more robust chemical coating on the clay surface. This coating acts as a chemical shield, which prevents subsequent wellbore fluids from interacting with the formation surface. A new chemical treatment has been evaluated and, as discussed in this paper, the laboratory test results indicate the application of a hydrophobic coating offers substantial clay protection in water sensitive environments.

The industrial importance of homogeneous catalysts in hydrogenation reactions lies mainly in their very high chemo-, regio-, and enantioselectivities. This chapter discusses hydrogenation reactions and other hydrogen-based catalytic reactions such as hydroformylation, hydrosilylation, hydrocyanation, and hydroamination. There are various industrial and patented processes where hydroformylation reactions are employed. Asymmetric hydroformylation allows the conversion of olefins into optically active aldehydes in a single step. From an industrial perspective, the hydrosilylation reaction where a new carbon-silicon bond is made has many uses. Examples are the coupling of silanes and siloxanes to organic polymers. Hydrocyanation reaction is carried out in two stages. In the hydrocyanation process, zero-valent nickel phosphine or phosphite complexes are used as precatalysts. Intramolecular hydroamination involving ring closures is illustrated in the chapter. In recent years the addition of amides to C ≡ C bonds has also been reported.

Abstract Complete fluid shutoff using crosslinked polymer gels represents an effective means of water control in reservoirs producing uneconomical volumes of water. To achieve this goal, a new organic crosslinker was developed for complete matrix shut-off in lower temperature reservoirs (80 to 140°F). The system uses a low molecular weight, crosslinked polymer that is injected directly into the target zone, reducing the permeability in the matrix. The crosslinker represents a significant improvement over traditional organic crosslinkers like polyethyleneimine (PEI) and chromium-based metallic systems. The new product has very similar gelation time (<12hr) profiles to the chromium systems, but requires shorter times than PEI, which could have gel times to ~24hr at 80°F. Additionally, the system has a much smaller environmental footprint, easing operator's concern over the sustainability of their chemical shutoff system. Results indicate that the new crosslinker yields ringing gels at lower dosages than traditional organic crosslinkers like PEI. (Sydansk gel code J). This product enables easy generation of ringing, rigid gels for low-temperature reservoirs within a reasonable gelation time (<12hr), making it ideal for applications including water shut-off, casing leak repairs, cement squeeze alternatives, zone abandonments, etc. It represents a cost-effective, environmentally friendly alternative to heavy-metal containing chromium systems where current available organic systems require longer shut-in times and increased concentrations to achieve similar gel strengths. A series of performance tests including laboratory core analysis was conducted to determine it's operating effectiveness. The product was successfully field tested in the Spraberry formation in the Permian basin.

Biocatalysis has made tremendous advances in the field of synthesis of industrially important products and intermediates. Cofactors are an important part of many enzymes which are involved in biocatalysis. These cofactors are expensive and stoichiometric additions are not economically feasible. This necessitates the in situ cofactor regeneration in biocatalytic processes. Various methods of regeneration of NAD(H)/NADP(H), an important class of cofactors, have been reviewed in this article. We discuss their salient features, suitability for current bioprocesses, drawbacks and scope of improvement.