Control of Formation Damage at Prudhoe Bay, Alaska, by Inhibitor Squeeze Treatment
- K.O. Meyers (Arco Resources Technology) | H.L. Skillman (Arco Resources Technology) | G.D. Herring (Arco Alaska Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 1985
- Document Type
- Journal Paper
- 1,019 - 1,034
- 1985. Society of Petroleum Engineers
- 4.3.4 Scale, 1.6.9 Coring, Fishing, 4.2.3 Materials and Corrosion, 4.1.2 Separation and Treating, 3.2.4 Acidising, 4.1.5 Processing Equipment, 1.8.5 Phase Trapping, 5.3.2 Multiphase Flow, 1.6 Drilling Operations, 1.8 Formation Damage, 2.2.2 Perforating, 5.2 Reservoir Fluid Dynamics, 3 Production and Well Operations, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.6.4 Drillstem/Well Testing
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Control of Formation Damage at Prudhoe Bay, Alaska, by Inhibitor Prudhoe Bay, Alaska, by Inhibitor Squeeze Treatment
A substantial number of wells in the Prudhoe Bay field have been damaged by the deposition of calcium carbonate (CaCO3) scale in the perforation tunnels and the near-wellbore formation sandstone. Inhibitor squeeze treatments have prevented this scale damage and the capacity loss resulting from it. Wells that had monthly decline rates greater than 10% before treatment have maintained their maximum capacity for more than I year. In some wells, treatment lives greater than 2 years have been obtained. This paper summarizes the laboratory design and field implementation of inhibitor squeeze treatments at the Prudhoe Bay field. First, the history, mechanisms, and Prudhoe Bay field. First, the history, mechanisms, and extent of the formation damage problem are reviewed. Next, the laboratory and field tests used to screen inhibitors and to design the squeeze treatments are detailed. Finally, the history and success of the treatments in the field are discussed.
More than 50% of the wells currently producing in the Prudhoe Bay field have experienced productivity decline Prudhoe Bay field have experienced productivity decline rates substantially greater than the I to 2% per month predicted from reservoir studies. This problem has predicted from reservoir studies. This problem has existed since the startup of the field. To mitigate the problem, a Well Damage Study Group was formed with problem, a Well Damage Study Group was formed with laboratory and operations representatives from the three major owners. 1-3 From drilling, completion, and well test data and diagnostic field treatments, the primary damage mechanism was identified as carbonate scale formation in the perforation tunnels and near-wellbore matrix. Analyses of bottomhole brine and scale samples revealed that the scale was composed almost entirely of CaCO3. Matrix and perforation washes with hydrochloric acid were successful in dissolving the scale and in restoring production. However, these production gains were lost production. However, these production gains were lost rapidly as unproduced spent acid mixed with formation brine, and the dissolved scale reprecipitated. To avoid the rapid capacity losses inherent in HCl washes, alternative treatments were sought. One approach was to use a chelating acid that would dissolve the scale and then bind the calcium ions in solution, preventing their reprecipitation. The design and field application of these treatments has been detailed by Shaughnessy and Kline.
Another approach was to use scale inhibitors in the near-wellbore matrix to inhibit the formation of CaCO3 scale. This paper details the laboratory design and field implementation of these inhibitor treatments at the Prudhoe Bay field. In the following section, the scale damage mechanisms and the mechanics of an inhibitor squeeze treatment are discussed briefly. The laboratory studies used to screen inhibitors and to design squeeze treatments then are detailed. Finally, the implementation and success of the laboratory design in the field are addressed.
Background. The average reservoir temperature in the Prudhoe Bay field is 200 degrees F [93 degrees C], and Prudhoe Bay field is 200 degrees F [93 degrees C], and the reservoir pressure ranges from 3,800 to 4,000 psi [26.2 to 27.6 MPa]. The brine of the Sadlerochit formation contains approximately 200 ppm Ca++ and 2,000 ppm HCO-3 and is in equilibrium with CO, (500 psi [3.4 MPa]) and CaCO3:
Perturbations that shift this equilibrium to the right result Perturbations that shift this equilibrium to the right result in the precipitation of CACO3. Two scaling mechanisms have been identified in the Prudhoe Bay wells. The first results from the reduction Prudhoe Bay wells. The first results from the reduction in CO, partial pressure, which unavoidably accompanies drawdown during production. CO2-saturated brine is throttled through the near-wellbore formation, and CaCO3 precipitates from solution. This precipitation is exacerbated by the low water cuts ( less than 5 %) present in most of the producing wells-i.e., as the fluids are throttled, CO2 is further stripped from the brine phase by partitioning into the predominant oil phase. partitioning into the predominant oil phase. The second scaling mechanism occurs when excess calcium ions are introduced into the formation. The source of the excess Ca ++ may be spent acid or CaCl 2 containing drilling/workover fluids. As these fluids equilibrate to reservoir CO, partial pressure or as they mix with reservoir brine, CaCO3 precipitation occurs. Scale inhibitors function at concentrations significantly below the levels required to sequester or to chelate divalent cations. The molar ratio of precipitate kept in solution to inhibitor is typically on the order of 10,000: 1. It has been postulated that scale inhibitors prevent, slow, or distort crystal growth by blocking growth sites. it is also believed that the inhibitors prevent the adhesion of scale to metal surfaces in some unknown manner.
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