A slow-release-hydrogen retarded-hydrofluoric-acid (SRH-RHF) system was used on the basis of a detailed candidate selection, case-specific fluid design for high-water-cut wells, and mechanism of fines and clay migration and control methodology to acidize heavy- or medium-crude reservoirs.
This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112558, “Increasing Production in a Brownfield With Heavy Crude and Fines Problems by Application of New HF-Acid System: Case Histories,” by Folorunso Afolabi, SPE, Austa Opusunju, SPE, and Jaspers Henri, SPE, Shell, and Cletus Onyekwere, SPE, Chris
Improving productivity in these Niger delta brownfields that produce heavy crude and experience fines migration had been approached with little or no consideration to such challenges as water production. Many wells were treated with a conventional mud-acid system, either with or without a solventsoak treatment. Clay-control agents are no longer used to stop fines problems because the additive had little effect. Wells with high water cut were treated only with solvent material, realizing minimal effect. Foam diversion often had inconsistent results. Other diverting techniques also proved unpredictable in this environment. A coating of heavy crude on the formation wall inhibited the reaction of the mud-acid system with the formation. An acid system or formulation that would maintain matrix acidizing was needed for well-productivity problems in the Niger delta. In December 1996, an SRH-RHF system was used. Data indicated a consistent production increase with evidence of deep penetration into the damaged zone. Failures experienced with this system were traced to a shortage of well information for proper diagnosis and the need for a core-flow test in one field with three treatments resulting in no increase or a reduction in production. In the past, acid stimulation was limited to wells with water cut less than 30%. In late 2001, an improvement was made in candidate selection, treatment design, foam diversion, and pumping method for high-water-cut wells and heavy-crude wells. The high-water-cut limit was increased to 60%. In 2005, a new SRH-RHF system was developed. Its application in nine wells with heavy or medium crude was successful.
The Niger delta basin is a prolific hydrocarbon province covering 80,000 sq km. Wells treated with the new SRH-RHF drain eight different reservoir sands. Most of the treated sands consist of several sequences of shale and sandstone with mostly medium-to-poorly consolidated sands. The sandstones are fine-tomedium quartz; poorly-to-moderately sorted smectite, kaolinite, and illite clays; with feldspathic and carbonate scale materials. Permeabilities of the treated intervals ranged from 500 to 2,000 md, and well bottomhole static temperatures ranged from 125 to 163°F.
Most of the operator’s oil wells are dual producers, typically completed with 23/8- to 31/2-in. tubing in a perforated cased hole or gravel packs with wire-wrapped screens inside perforated casing.
Production impairment is believed to be heavy-hydrocarbon precipitation, clay swelling, fines migration, wettabil-ity alteration, and, to a lesser extent, hydrate formation and treatment-fluid damage. Associated damage mechanism may be scale deposition caused by filtrate invasion, especially in wells with high water cut, with occasional problems with emulsions and formation-/treatment-fluid incompatibility.
Fines are quartz or clay particles smaller than 44 ?m. The origin of fines is multiple and complex, thus making it prevalent in most oil fields. Damage caused by fines migration often is worsened by associated-water production, high oil viscosity, and crude-oil gravity. Fines cause damage by blocking pore throats and acting as nucleation particles for heavy-hydrocarbon deposition and emulsion stability.
There is a critical fluid-flow rate beyond which the hydrodynamic force exceeds the binding forces holding fines particles together, and the fines begin to move. A sudden increase in flow rate also could induce fines migration, such as when choke sizes are changed or not designed properly. Intermittent gas lift and uncontrolled flowback after stimulation can induce fines migration. In the case of kaolinite, illite, and nonclay fines that are attached loosely to formation pores, exceeding the critical flow rate will dislodge and migrate fines.
Particle wettability and interfacial forces influence particle mobility. With multiphase flow, particles will move only when the wetting phase moves. Because fines and clays often are water-wet, water production or backproduced water-based treatment fluids likely will cause fines to dislodge and induce mobility. When only oil is flowing, little or no fines migration exists.
Injection of water-wetting treatment fluids or surfactant/solvent can mobilize fines that are held in place by wettability phenomena or interfacial forces.
Simultaneous flow of water and oil will cause fines to migrate because water is mobile enough to dislodge the fines. Local pressure disturbance caused by multiphase flow keeps fines agitated and reduces the opportunity to develop permanent bridges.
Many of the studied wells produce heavy crudewith gravity between 22.3 and 10°API. The challenges encountered in acidizing heavy crude include high sludge tendency from treatment-/formation-fluid incompatibility, resulting in a high tendency for emulsion production after acidizing. Also, viscous crude could inhibit treatment fluids from reacting with damaging material if the treatment fluid is not properly designed The resulting low production or insignificant oil gain often is caused by poor candidate selection, possibly through improper or poor well analysis. The high-viscosity heavy crude often limits most HF treatments, especially a nondeep-penetrating HF system, to the near-wellbore region where most of the HF system is spent on clays having very large surface area compared to quartz.
Candidate selection involves analysis of the production-performance history, experience with heavy-crude behaviors, and good analytical skills. A full systems analysis can establish the extent and severity of the damage. Also, the gas/oil ratio, tubinghead pressure, water and gross-fluid production, bottomhole-pressure (BHP) trend, type of (removable) skin damage, information on nonremovable damage, and reservoir pressure are considered in the analyses to assess adequately the feasibility of acidizing. Most of the treated wells are within a screening envelope for matrix stimulation. This screening includes economical remaining reserves, productivity index (PI) <10 (obtained from BHP survey), a flow efficiency (ratio of actual to ideal PI) <0.5, and PI decline >30%. Good knowledge of the water source is important in highwater-cut-well stimulation. A full systems analysis, including cement-bond and porosity logs and production and permeability profiles, is carried out to establish the source of water and severity of the damage. Interval mineralogy, reservoir/damage permeability, and frequency and previous acid stimulations are considered.
To confirm the presence of impairment and to characterize potential improved production from these candidates, nodal-analysis simulations were run in three stages.
• Pressure/volume/temperature matching enables accurate prediction of fluid properties during vertical lift.
• Gradient analysis obtained from correct pressure and test data helps to determine the appropriate wellbore correlation for the prediction of bottomhole flowing pressure.
• Systems analysis quantifies damage and defines the range of expected production increase.
It is necessary to evaluate the fluid pumped into the formation to determine the treatment formulation. In many low-pressure wells, diesel oil or a diesel/xylene mixture is used for a prestimulation injectivity test. However, the oil-phase fluid can cause problems when the near-wellbore water saturation is high (as in high-water-cut wells). The oil-phase fluid will cause the formation to become more oil-wet and will occupy the pores in water-producing zones. The effect is reduced oil mobility, increased water and fines mobility, and destabilizing the foam pad placed to divert the acid system from the water zone or high-permeability zones. The new approach uses a water-wetting 3% ammonium chloride (NH4Cl) salt solution for the injectivity test. Approximately 10 to 20 bbl in excess of the coiled-tubing (CT) or tubing volume is used. This water-wetting fluid acts as a hole-conditioning fluid before foam-pad placement. NH4Cl is compatible with most formations and with acid and foam systems. When injectivity is low, acid is spotted with CT and injectivity is repeated.
Fluid design (or acid recipe) depends on the damage mechanism and results of core-flow tests if available. Usually, production impairment in the treated reservoir sands was the result of fines migration and, to a lesser extent, clay dispersion and swelling. A conventional acid recipe was designed with a solvent soak for reservoirs with heavy oil or a history of organic deposits (e.g., wax, asphaltene, and paraffin). The pumping sequence [solvent soak (an oil phase flowed back before foam or acid), foam, foam pad, and then acid] resulted in destabilizing the foam in the near-wellbore region. Use of a soak treatment, without flowback before pumping, retained foam stability and helped displace or push back the fines. The modified sequence [solvent (oil-phase injection with a wetting agent and no flowback), foam, foam pad, and then acid] minimized possible foam contamination by the organic solvent.
Placement and Diversions.
Several diversion techniques improve treatmentfluid placement into the zone of interest. Mechanical techniques include straddle packers, wash cup, and ball sealers, while chemical techniques use viscous fluids, foam solutions, and oil-soluble resin. Because the pumped fluid will take the path of least resistance, it is vital to select the placement method and diversion techniques carefully for stimulating high-water-cut wells. Most of the studied wells are in highly permeable heterogeneous reservoirs with a gravel pack across producing intervals that range from 10 to 50 ft long. Acid placement in a few of the wells was carried out with CT, while most jobs were performed by bullheading treatment fluid into the formation. Foam diversion was used in selective stimulation of oil zones preferential to water zones and to aid the effective distribution of treatment fluids in zones with a perforated interval greater than 15 ft. Identifying the water source or point of inflow into the wellbore is essential in designing the foam pad for diverting acid from the water zone. Matrix stimulation of intervals having water influx from high-permeability zones in a heterogeneous reservoir will benefit more from foam diversion. Treatment of a reservoir in which water influx is from a lowpermeability zone (water encroachment or mature coning effect) or zones with homogeneous permeability could be achieved by increasing the foam pad. In this case, the foam is expected to degrade faster in the oil phase. The volume of foam required is estimated at 25 to 30% of main treatment volume, and 65- to 70%-quality foam was used.
Maximum Safe Injection Rate and Pressure.
The formation-fracture pressure (or maximum surface-pumping pressure) is considered in the decision. Use of CT is preferred with long intervals (greater than 200 ft) having a permeability contrast greater than 300 md. Preference also is given to the use of CT for horizontal wells with zones longer than 400 ft. Bullheading at maximum safe pressure is a suitable approach to short-string-interval stimulation when the CT cannot access that portion of the wellbore. The rate available through the CT can be limited especially in some high-production intervals with high water cut. Most fluids (even foam pad) pumped through CT degrade before acid injection as a result of the long pumping time at the low rates and accompanying high CT pumping pressure, leading to stimulation of the water zone and reduction in acid-penetration depth. A successful treatment was achieved with the combination of high-rate pumping (bullheading) of treatment fluids and foam diversion. During high-rate and foam-diversion operations, production tubing is pickled with 10% hydrochloric acid. The pickling fluid usually is nitrified and lifted out of the tubing (with a plug set in the deepest nipple profile) to prevent ferrous scales and rust from contaminating the stimulation recipe or entering the formation.
New Retarded-HF System.
Retarded acid is a slow-reacting acid system or an acid system with a controlled rate of reaction. This slowed reaction with formation-damaging material enables deeper penetration into damaged zones and prevents formation of damaging byproducts. The SRH-RHF system is formed both at the surface and in-situ. The HF is generated through slow release of hydrogen ions by an organic salt, acid, or ester compound with multiple hydrogen atoms capable of ionizing into solution for replacement reaction or endothermic reaction. The delayed release of hydrogen assists in deep penetration of the formation. In 2005, a new acid system was developed that generates HF from the reaction between ammonium bifluoride and an ester compound with multiple hydrogenions. The release of the hydrogen ion from this ester is governed by pH changes, first at the surface and later in-situ. The consumption of one hydrogen ion will shift the equilibrium and, thus, release additional hydrogen ions to balance the system. The end product of the ester compound is a good wetting agent. Its slow reaction reduces fines size and allows longer reaction time on the formation without deconsolidation.
Laboratory Analysis and Fluid Selection.
Field trial by the operator of any new acid system is allowed after detailed core-flow tests and fluid-compatibility tests confirm that the new acid system is better than a conventional acid system. Core-flow-test results of the SRH-RHF system proved that the retarded-acid system has superior performance over regular mud acid. However, for all the treatments carried out, compatibility tests between treatment fluid and formation fluids were conducted and recipes were modified until the sludge and emulsion tendency was eliminated. Fluids were not pumped until a clean mixture was observed in each case, indicating no insoluble precipitates formed when commingled.
Of the 10 intervals analyzed for this paper, seven were heavy crude and two had medium crude. They also had water cuts between 17 and 36%. Seven of these stimulation candidates had been treated earlier with mud acid before the application of the new SRH-RHF system. The importance of selection of placement methods, injection-fluid types, and recipe designs also was part of the analysis.
All of the heavy-crude wells treated with this new approach demonstrated a significant increase in PI; longer productivity; and reduced, or minimal increase in, water cut after the treatment. Skin damage was removed in most cases, while true stimulation (negative skin) was recorded in two cases. The partial success experienced in one case could be attributed to poor planning that led to keeping spent acid in the critical near-wellbore region overnight because of a lack of liquid nitrogen and loss of lift gas. The reduced water cut and sustained production seen in most of the wells were the result of the effectiveness of foam diversion and high-rate pumping along with high-water-wetting, scaleinhibition, and deep-penetrating characteristics of the SRH-RHF system and fines stabilizer.
Fig. 1 shows that wells treated with this technique had considerable incremental production compared with marginal gains from previous techniques used on the same wells. The wells treated with the new SRH-RHF system paid back faster (within 20 days) than previous mudacid treatments (100 days). The fulllength paper details the treatments and results of the nine heavy- and mediumoil intervals. JPT
For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt.
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