No abstract

Many oil wells in the Permian Basin have reported sludging problems associated with acid stimulations. The acid sludge is similar among wells and was identified as a viscous emulsion stabilized by asphaltene-rich organic solids. The sludging tendency of the oil increased with the concentrations of asphaltenes and resins, base number of the oil, and ferric ion content in the acid. Only three out of nine commercial acid systems tested were effective in preventing acid sludge formation; they all utilize the same novel iron control technology, i.e., catalytic reduction of ferric ions. Several commercial and generic solvent systems were effective in dissolving acid sludge, induding mixtures of an aromatic solvent (e.g. xylene) with either isopropyl alcohol (2: 1 volume ratio) or EGMBE (2: 1 to 3: 1 volume ratios). Selection of acid formulations and solvent systems was based on cost effectiveness and operation safety. Field implementation proved successful. If the results of this study had been implemented earlier in the lives of some of the Permian Basin properties, the recovery of 574 BOPD of lost or deferred production from 99 wells could have been realized. This would have resulted in an estimated increased revenue of over $3 million in one year.

Many oil wells in the Permian Basin have reported sludging problems associated with acid stimulations. The acid sludge is similar among wells and was identified as a viscous emulsion stabilized by asphaltene-rich organic solids. The sludging tendency of the oil increased with the concentrations of asphaltenes and resins, base number of the oil, and ferric ion content in the acid. Only three out of nine commercial acid systems tested were effective in preventing acid-sludge formation; they all use the same novel iron control technology, Le., catalytic reduction of ferric ions. Several commercial and generic solvent systems were effective in dissolving acid sludge, including mixtures of an aromatic solvent (e.g., xylene) with either isopropyl alcohol (2: 1 volume ratio), or ethylene glycolmonobutylether (EGMBE) (2: I to 3: I volume ratios). Selection of acid formulations and solvent systems was based on cost effectiveness and operation safety. Field implementation proved successful. If the results of this study had been implemented earlier in the lives of some of the Permian Basin properties, the recovery of 574 BOPD of lost or deferred production from 99 wells could have been realized. This would have resulted in an estimated increased revenue of over U.S. $3 million in I year.

One of the most important rock properties in Reservoir Engineering is very often absolute permeability. Unconsolidated sands offer some of the highest permeabilities due to their typically low consolidation degree, leaving more space between the porous media for conductivity. This low degree of consolidation, however, also brings high sand production potential while producing the reservoir; therefore sand control is required. This paper discusses how well failure histories were used, along with downhole analytical methods, to determine maximum FLUX limitations recommended to be used to minimize completion failures and sand production while producing at the highest safe rate.Chevron has a 50% working interest in an NOJV area with BG, in three different offshore dry gas fields located in Trinidad and Tobago. Dolphin field is the main producing field, having been on production since 1996 from four main groups of sands, all of which are unconsolidated (D, Upper E, Lower E and G sands). Due to the sands highly unconsolidated nature and targeting high gas production rates, all completions in the field utilize openhole gravel packs for sand control.During the field production history, several sand completion failures were encountered, as evidenced by formation sand production at the surface and reduced rates; and in some cases, complete cessation of flow (due to sand fill). After completing various analyses on possible failure root causes, it was found that the highest probable reason for sand completion failure was high FLUX across the completions. After drawing this conclusion, it was imperative for the Reservoir Management and Production Teams to understand FLUX associated with the failures, determine the maximum recommended FLUX to avoid future failures and finally, to apply a FLUX limit on current and future forecasts, from a prudent reservoir management perspective, in order to develop more realistic and reliable production forecasts.This case study shows how the failure history data was used and integrated with a downhole velocity analytical approach in order to determine the maximum FLUX limit to prevent current and new completion failures and sand production.

Many oil wells in the Permian Basin have reported sludging problems associated with acid stimulations. The acid sludge is similar among wells and was identified as a viscous emulsion stabilized by asphaltene-rich organic solids. The sludging tendency of the oil increased with the concentrations of asphaltenes and resins, base number of the oil, and ferric ion content in the acid. Only three out of nine commercial acid systems tested were effective in preventing acid sludge formation; they all utilize the same novel iron control technology, i.e., catalytic reduction of ferric ions. Several commercial and generic solvent systems were effective in dissolving acid sludge, including mixtures of an aromatic solvent (e.g. xylene) with either isopropyl alcohol (2:1 volume ratio) or EGMBE (2:1 to 3:1 volume ratios). Selection of acid formulations and solvent systems was based on cost effectiveness and operation safety. Field implementation proved successful. If the results of this study had been implemented earlier in the lives of some of the Permian Basin properties, the recovery of 574 BOPD of lost or deferred production from 99 wells could have been realized. This would have resulted in an estimated increased revenue of over $3 million in one year. Introduction Various fields in the Permian Basin in West Texas have reported a "sludging" problem associated with acid stimulation. This sludge, more commonly known as "acid sludge," was found to occur in both producer and injector wells in the Permian Basin. In some cases, acid sludge was related to CO2 breakthrough. Samples recovered from all of the above situations appeared to be quite voluminous, viscous, and stable indefinitely. This resulted in a dramatic reduction of oil production or water injection rate in some of the wells. Early studies have revealed that crude oils in many producing areas of the United States and Canada form acid sludge upon contact with acid. The acid sludge potentially plugs pore throats, pores, vugs, wormholes, and natural fractures and produces skin damage which significantly reduces permeability in the near-wellbore region. Acid sludge can cause damage that partially, if not totally, offsets the stimulating benefit of the acid. However, the composition and chemical structure of acid sludge have not been well understood. It has been reported that acid sludge is asphaltenic in nature; can exist in some form of an emulsion, solids, or a mixture of both; and may not dissolve in solvents. Asphaltic components of crude oils, which are generally present in colloidal state, are apparently destabilized by low pH as a result of acid contact.