Modeling In-Situ Scale Deposition: The Impact of Reservoir and Well Geometries and Kinetic Reaction Rates
- E.J. Mackay (Heriot-Watt U.)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Facilities
- Publication Date
- February 2003
- Document Type
- Journal Paper
- 45 - 56
- 2003. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 3.1.2 Electric Submersible Pumps, 1.8 Formation Damage, 5.1.1 Exploration, Development, Structural Geology, 4.3.4 Scale, 6.5.4 Naturally Occurring Radioactive Materials, 4.1.5 Processing Equipment, 6.5.2 Water use, produced water discharge and disposal, 5.6.5 Tracers, 5.2 Reservoir Fluid Dynamics, 5.5 Reservoir Simulation, 5.2.1 Phase Behavior and PVT Measurements, 5.3.1 Flow in Porous Media, 5.5.8 History Matching, 4.3 Flow Assurance, 4.1.2 Separation and Treating
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Previous work has demonstrated how and where the mixing of incompatible brines occurs in waterflooded reservoirs and what the impact on scale prevention strategies is in terms of timing and placing squeeze treatments. This paper extends this work by modeling the resulting in-situ deposition process. The location of maximum scale deposition and the resulting brine compositions at the production well are calculated for a range of sensitivities, including reservoir geometry (1D, 2D areal and vertical, and 3D), well geometry (location and orientation within the field and with respect to other wells and the aquifer), and the reaction rate (ranging from no precipitation to equilibrium).
In conventional systems with no aquifer, it is demonstrated that maximum scale deposition occurs in the immediate vicinity of the production wellbore; therefore, low produced-cation concentrations indicate inadequate squeeze treatments. In systems in which water injection is into the aquifer, low cation concentrations may also result from deposition deeper within the reservoir. Maximum scale dropout still occurs as the fluids approach the production well but is sufficiently far from the wellbore to be unaffected by squeeze treatments or to have any major impact on productivity. The reaction rate is critical in determining the amount of scale deposition; however, even under equilibrium conditions, sufficient concentrations of scaling ions are delivered to the production well to necessitate squeezing it but with lower inhibitor volumes. Once cation concentrations have been reduced, it is predicted that they will never increase again.
This paper also discusses some of the limitations of modeling such systems, including determination of kinetic reaction rates, mixing zone size, and impact on permeability. Although the thermodynamics are fairly well understood, the kinetics are much more difficult. The size of the mixing zone is affected by numerical dispersion, and computationally intensive techniques are required to overcome this problem. Previous experience shows that formation damage factors are very difficult to extrapolate from coreflood data because there is a great difference between the dimensions of the mixing zone in the reservoir and the core plug.
Oilfield scales are hard mineral compounds that precipitate from brine solution and may adhere to solid surfaces in the reservoir, production tubing, or surface facilities.1 Scale accumulation will constrict fluid flow, limit production, and possibly cause damage to downhole equipment, such as electrical submersible pumps (ESPs). Safety may be compromised by scale deposition in subsea safety valves, and some scales constitute a health hazard, because they are naturally occurring radioactive materials (NORM) that may be expensive and dangerous to remove and dispose of.
There are two principal types of scale - carbonate and sulphate. The two types form by different mechanisms, yet both cause damage in production wells and their immediate environs.
A reduction in pressure or an increase in temperature may cause calcium (Ca) and bicarbonate (HCO3) ions in produced water to precipitate as calcium carbonate [calcite (CaCO3)].2 As the fluid pressure drops to less than the carbon dioxide (CO2) bubble point, CO2 is released from solution into the gas phase, and CaCO3 precipitation occurs. Additionally, as CO2 is lost from solution, the brine pH increases, reducing the solubility of CaCO3 and compounding the problem.
The greatest pressure drops occur when fluids are brought to the surface through the production tubing, typically forming carbonate scales in production wells that accumulate in the production string or the surface facilities. Mechanical constrictions or devices in the well cause greater pressure drops and, therefore, may be particularly prone to scaling. ESPs, which not only create greater pressure drops but also increase the fluid temperature because of heat generated by the pumps, are doubly at risk. Precipitation of carbonate scale may occur early in the field life, as soon as formation waters are produced.
Carbonate scales are typically softer and tend to be acid-soluble. Thus, they can be removed from the wellbore by washing it with the appropriate dissolvers. If the reservoir is being depleted, the CO2 bubblepoint may migrate down the production string and into the formation; at this point, the scaling problem becomes more difficult to treat. However, in most cases, application of chemical inhibitors can prevent carbonate scale accumulation in the wellbore and in the formation, if required.
As well as calcite, other acid-soluble scales include iron carbonate [siderite (FeCO3)], iron sulphide [pyrite (FeS2)], and various iron oxides (e.g., Fe2O3).
Reservoir performance can be improved by injecting brines, such as seawater, to drive oil toward production wells and to maintain the reservoir pressure. Pressure maintenance prevents gas coming out of solution in the reservoir, thus reducing oil mobility by competing for pore space. It also ensures a greater drawdown (or differential between the reservoir pressure and the well bottomhole pressure) in the production wells, and, thus, higher production rates can be maintained.
However, the injected brine may be incompatible with the existing formation brines.3 Most commonly, barium (Ba) ions in the formation water and sulphate ions (SO4) in seawater will precipitate to form barium sulphate scale [barite (BaSO4)] when the two waters mix. The most common acid-insoluble scale is BaSO4, but others also occur in oilfield systems, including strontium sulphate [celestite (SrSO4)] and calcium sulphate [anhydrite (CaSO4) or gypsum (CaSO4.2H2O)]. Because BaSO4 is difficult to dissolve, applying inhibitors (often by squeeze treatments) is the preferred method for managing it. Alternatively, if control by squeezing will be problematic, a sulphate-reduction plant may be used to remove most of the SO4 ions before water injection.
The potential for scale formation is largely determined by the composition of the brines involved. However, the mechanism that causes the precipitation of carbonate scales (usually changes in fluid pressures and temperatures) is quite different from what drives sulphate scale precipitation (usually brine mixing). This paper considers only the effects of brine mixing, thus concentrating on the formation of sulphate scales without addressing carbonate scales. Examples presented in this paper describe the precipitation of BaSO4 because it is the most common form of sulphate scale in oilfield systems.
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