The success of a stimulation treatment or gravel packed completion is often dependent on the ability of the diverting agent to force the acid treatment into different portions of the reservoir. Diversion of acid treatments in the Gulf of Mexico (GOM) have been predominately accomplished by using either foam, HEC, or particulate matters to "temporarily" block off the zones and force the acid elsewhere. Recently, viscoelastic surfactant based diverting agent has been successfully used in acid stimulation in GOM. The fluid generated its viscosity through the densely packed surfactant aggregations, called vesicles. Normally, densely packed conventional surfactant vesicles require high concentration of surfactant to generate adequate viscosity. A new fluid was developed by incorporating a polyelectrolyte with the surfactant to facilitate the vesicle formation, to reduce surfactant concentration and to enhance thermal stability of the fluid. The rheological properties of the fluid can be adjusted by fluid pH, surfactant concentration, and properties of polyelectrolyte and temperature. An internal breaker package was developed to break the surfactant gel and reduce the fluid viscosity to that of water at the desired time and temperature. This system does not require contact with formation fluids, brines, or acids for clean up to provide optimum production. The Core tests were performed and the results demonstrated that there is no formation damage observed in treated core. This paper describes the fluid properties at various pH's, surfactant and polyelectrolyte concentrations, temperatures, internal breaker loading, and salt concentrations along with two successful case histories. Introduction Matrix acid stimulation has been extensively used as ways to stimulate the production, remove formation damage caused by drilling mud invasion, clay swelling and clay migration. For most matrix acid treatments, acid is injected into the reservoir below fracturing rates and pressures, and the fluid will typically enter the region with the highest permeability. In most cases this is the portion of the reservoir that will benefit the least from stimulation due to the apparent "cleanliness" of the reservoir. Without proper diversion, acid tends to flow to the higher permeability zone and leaving the low permeability zone untreated. High rate water packs are extensively used as standard sand control treatments, especially in the GOM. Before or after the placement of gravel with completion fluids, low-density brines, or linear gels, a large acid treatment is pumped to remove the near wellbore formation damage or high skins encountered more often in overbalanced perforation wells1,2. In other cases, a clay acid package is often pumped into the formation before the gravel pack to stabilize the residual clay. The results of these treatments are often directly related to the ability of the acid treatment to remove the near-wellbore damage and connect the wellbore to the formation. In addition to determining the most effective combination of acid blends and volumes for each particular reservoir, treatment design and planning are done to insure that the correct procedure is followed to place the acid across the entire interval. Staging of the treatment is used to force acid across the entire interval, treating the damaged clean portion of the sands. The successful acid placements in matrix treatments of openhole horizontal wells are even more difficult due to the length of the zone treated and potential variation of the formation properties. A successful diversion technique is critical to place the acid to the location where damage exists. Without good diversion, the results of the acid treatment could lead to either incomplete damage removal and/or requirements for uneconomical volumes of treatment fluids. A well-developed diverting agent that does damage the formation after the treatment is critical to the success of any matrix acid stimulation treatment and successful sand control completion.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractViscoelastic surfactant (VES) based diverting fluid has been successfully used in matrix acidizing in the Gulf of Mexico in recent years. Some cases are acid stimulation to remove near wellbore formation damage, or to cleanup perforation channels prior to gravel or frac packing, while other cases are acidizing to remedy fines migration or inorganic scaling damage on previously frac/gravel packed completions. Success or failure of these treatments is often related to the efficiency of diverting agents, especially for acid treatments on wells with long intervals or multiple-zone completions. A VES diverting agent is of particular interest to remedial treatments of frac/gravel packed wells, since damage to the near wellbore area and completion needs to be minimized for optimum production. Lab studies and field applications have demonstrated the non-damaging properties of a VES fluid.This paper presents several case histories of VES diverting applications in the GOM, including acidizing prior to frac/gravel packing, and remedial treatment of a frac packed completions. The bottom hole static temperature of these cases range from 140° F to 290° F for gas and oil wells. Because of an internal breaker system, the diverter does not require contact with formation fluid, brine, or acid to clean up and provide optimum production. In some cases, as many as four stages of diverters were pumped for the entire acid treatment, and successful diversion was observed for each stage. The paper will detail the general fluid properties as well as fluid properties tailored to specific well conditions and formation characteristics. Details and pressure response of the treatments will be discussed.
Viscoelastic-surfactant (VES)-based diverting products have been used successfully in matrix acidizing in the Gulf of Mexico (GOM) in recent years. The uses of VES diverters range from remedial matrix-acid or nonacid-cleanup treatments to use before gravel-or frac-packing operations to clean up long intervals after perforating. Success or failure of these treatments is often related to the efficiency of diverting agents, especially for acid treatments on wells with long, heterogeneous intervals or multiple-zone completions. A VES diverting agent is of particular interest to remedial treatments of frac-/gravel-packed wells, because damage to the near-wellbore area and completion should be minimized for optimum production. Laboratory studies and field applications have demonstrated the nondamaging properties of a VES fluid.This paper reviews the properties of the vesicular-type VES diverting fluid, reviews the operational considerations, and presents several case histories with VES diverting agents in the GOM. The bottomhole static temperatures (BHSTs) of these cases range from 140 to 290°F for both gas and oil wells. With an internal breaker system, the diverter does not require contact with formation fluid, brine, or acid to clean up and provide optimum production. In some cases, as many as four stages of diverters were pumped in the treatment, and successful diversion was observed for each stage. The paper outlines field-operational considerations and detailed fluid properties, which were tailored to specific well conditions and formation characteristics. Details and pressure responses of the treatments are discussed.
Because of the problems associated with hydroxyethyl cellulose (HEC), several water soluble polymers were evaluated to replace HEC used to viscosify completion and workover fluids. The rheological properties and formation damage tendencies of these polymers were initially tested in dry form in various brines at elevated temperatures. Then the same polymers were prehydrated and re-evaluated in high dense brines (above 11.6 ppg). The results showed that HEC is no longer the preferred polymer. The preferred polymer at equal polymer concentrations outperformed HEC in nearly all cases based on rheological and formation damage tests. The preferred polymer does not have a tendency to precipitate at elevated temperatures like HEC does in sodium and potassium chloride solutions and unlike HEC can viscosify brines containing a particular concentration range of zinc at any density. This polymer can be used to thicken formate brines where HEC is not recommended. As a result, the polymer was implemented into the field and successful case histories are presented. Introduction During 1967, Shell began testing completion fluids to determine the effect on well productivity due to sand control failures. In 1974 Tuttle and Barkman published the results on that research.1 They described that filtering brine through 2-micron cartridge filters resulted in the lowest rate of impairment in about a 1 darcy to air sandstone core. By not filtering, 10% to 30% regained permeability could not be obtained even by flowing more than 100 pore volumes of acid. During those years, guar gum was added to completion fluids for fluid loss control and viscous sweeps to remove sand and drill cuttings from the hole. Shell also reported severe formation damage using guar gum with filtered brine and concluded that guar gum solutions can reduce the permeability by a factor of 4 and that this damage could not be removed by enzyme breakers or acids.2 Because of these findings, Shell researched other polymers and found that hydroxyethyl cellulose (HEC) provided less damage than guar gum when tested at 1.5 lb./bbl. Using unbroken HEC caused formation impairment by a factor of about 2 while broken HEC showed nearly no formation damage when flowing in the reverse direction. So dramatic were these findings, that even today, completion brines are filtered through 2-mircon cartridge paper and HEC is commonly the preferred polymer for providing increased viscosity for fluid loss control and viscous sweeps. Tuttle and Barkman's results were expanded to other water soluble polymers. Lipton and Burnett tested xanthan gum, hydroxypropyl guar (HPG) and polyacrylamide. They basically showed that HEC was less damaging than guar or HPG although, only 0.5 pore volumes of the viscous fluid was injected into Berea cores ranging in permeability from 658 to 820 md.3 The authors also showed that xanthan gum was slightly less formation damaging than HEC (15% compared to 21%).
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