Eric James Mackay

Mixing of injected, connate and aquifer brines in waterflooding and its relevance to oilfield scaling

Abstract Waterflooding is one of the most common methods of oil recovery although it does lead to certain production problems after water breakthrough, e.g. corrosion, scaling, etc. The issue of concern in this paper is mineral scale formation by brine mixing as occurs in barium sulphate (barite, BaSO 4 ) scaling. Barite formation in the production well and tubulars occurs in many oilfields when sulphate-rich injection water (IW) (often seawater (SW)) mixes with barium-rich formation water (FW) close to or in the wellbore. However, when a brine is injected into the reservoir, it may mix to some extent with the formation (or connate) brine deep within the system. Such in situ mixing of barium-rich and sulphate-rich brines would certainly result in barite deposition deep within the reservoir due to the low solubility and rapid kinetics of this precipitation process. Conversely, in order to estimate how much of this type of in situ precipitation might occur in reservoirs, we must be able to model the appropriate displacement processes incorporating the correct level of dispersive brine mixing in the reservoir formation. In this paper, all of the principal mechanisms of brine mixing in waterflood displacements are considered and modelled. Mixing between the IW, the oil leg connate water (CW) and the aquifer water (AQW) is analysed starting from a one-dimensional (1D) frontal displacement, extended Buckley–Leverett (BL) analysis. This particular mechanism occurs in all other types of displacement and reservoir mixing process including those in both heterogeneous layered systems and in areal flooding situations. Of vital importance to brine mixing is the level of reservoir sandbody dispersivity, and field values of this quantity are estimated. Results from the numerical modelling of oil displacement and IW/FW mixing are presented to illustrate various points which arise in the discussion. These calculations show that quite complex patterns of mixing of connate, aquifer and injection brines can occur in relatively simple two-dimensional (2D) systems. The significance of in situ brine mixing to barite scaling is discussed in some detail.

Modeling in-situ scale deposition: the impact of reservoir and well geometries and kinetic reaction rates

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 (ID, 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.

Predicting in Situ Sulphate Scale Deposition and the Impact on Produced Ion Concentrations

Simulation models may be used to predict not only where the mixing of incompatible brines occurs in water-flooded reservoirs, but also the impact of in situ deposition on scaling ion concentrations in and around the production wellbore. The location of maximum sulphate scale deposition and the resulting brine compositions at the production well are calculated for a range of sensitivities, including reservoir properties (layered, homogenous, aquifer), well geometry (location and orientation within field and with respect to other wells and the aquifer), and various production scenarios (desulphation and squeeze treatment). In conventional systems with no aquifer, it is demonstrated that maximum scale deposition occurs within or in the immediate vicinity of the production wellbore, and therefore low produced cation concentrations would indicate that squeeze treatments have not been successful. In systems where water injection is into the aquifer, low cation concentrations may result from deposition deeper within the reservoir. Maximum scale dropout still occurs as the fluids approach the production well, but may be sufficiently far from the wellbore not to have any major impact on productivity, or to be affected by squeeze treatments. However, sufficient concentrations of scaling ions are still delivered to the production well to necessitate squeeze treatments, although using lower volumes of inhibitor. Once cation concentrations have been reduced by deposition deep within the reservoir, it is predicted that they will never pick up again. This paper also assesses the impact of desulphation and produced water re-injection on scale deposition in the reservoir, and the need to protect injection and/or production wells is discussed.

Impact of Brine Flow and Mixing in the Reservoir on Scale Control Risk Assessment and Subsurface Treatment Options: Case Histories

As offshore production environments become ever more complex, particularly in deepwater regions, the risks associated with formation damage due to precipitation of inorganic scales may increase to the point that production by conventional waterflooding may cease to be viable. The ability to predict and control such formation damage can thus become critical to project success under such circumstances. The work described in this paper presents how the risk may be managed from early in the CAPEX phase of projects through to the OPEX phase by use of reservoir simulation tools to better understand the scaling potential in a reservoir and the possibilities for effective scale control. This process is illustrated by reference to a number of field examples where specific scaling problems have been identified, and the ability to implement effective scale management has been impacted by detailed fluid flow and brine-mixing calculations.

Evaluation of the CO2 Storage Capacity of the Captain Sandstone Formation

The volume of CO2 that can be stored in the Captain Sandstone formation in the North Sea was investigated by building a geological model and performing numerical simulations. These simulations were also used to calculate the best position for the injection wells, and the migration and ultimate fate of the CO2. The overall migration of CO2 and the pressure response over the entire formation was studied by the calculated injection of 15 million tonnes CO2 per year. The injection rate was restricted to a maximum of 2.5 million tonnes CO2 per year for each of a possible 15 wells considered. An important objective was to predict how to avoid flow of the injected CO2 toward potential leakage points, such as the sandstone boundaries and faults. The migration of injected CO2 towards existing oil and gas fields was also a determining factor. The summary conclusions are: - The Captain Sandstone formation has significant potential CO2 storage capacity. Even with all boundaries closed to flow, the probable storage capacity is calculated to be about 358 million tonnes, giving a storage efficiency of 0.6% of pore volume, with an expected operating life-span of 15-25 years. - The possible storage capacity of the formation may be at least four times greater if the aquifer boundaries are open. This increase would be a result of displacement of salt water, and not CO2. - The storage capacity if the sandstone is closed to flow may be increase from 358 to 1668 million tonnes of CO2 by significant additional investment in 15 to 20 water production wells. - Injection of up to 2.5 million tonnes CO2 per year in one well has an impact on the pressure throughout the entire formation, and thus interference between different injection locations must be considered.

Simulation of CO2 storage in a heterogeneous aquifer

Abstract The fate of carbon dioxide (CO2) injected into a deep saline aquifer depends largely on the geological structure within the aquifer. For example, low permeability layers, such as shales or mudstones, will act as barriers to vertical flow of CO2 gas, whereas high permeability channels may assist the lateral migration of CO2. It is therefore important to include permeability heterogeneity in models for numerical flow simulation As an example of a heterogeneous system, a model of fluvial-incised valley deposits was used. Flow simulations were performed using the generalized equation-of-state model—greenhouse gas software package from Computer Modelling Group, which is a compositional simulator, specially adapted for CO2 storage. The impacts of residual gas and water saturations, gas diffusion in the aqueous phase, hysteresis, and permeability anisotropy on the distribution of CO2 between the gaseous and aqueous phases were examined. Gas diffusion in the aqueous phase was found to significantly enhance solubility trapping of CO2, even when hysteretic trapping of CO2 as a residual phase is taken into account.

The impact of pressure-dependent interfacial tension and buoyancy forces upon pressure depletion in virgin hydrocarbon reservoirs

This paper describes a combined experimental and theoretical study of the microscopic pore-scale physics characterizing gas and liquid production from hydrocarbon reservoirs during pressure depletion. The primary focus of the study was to examine the complex interactions between interfacial tension and buoyancy forces during gas evolution within a porous medium containing oil, water and gas. A specialized 2-dimensional glass micro model, capable of operating at pressures in excess of 35 MPa was used to visualize the physical mechanisms governing such microscopic processes. In addition, a 3-dimensional, 3-phase numerical pore-scale simulator was developed that can be used to examine gas evolution over a range of different lengthscales and for a wide range of fluid and rock properties. The model incorporates all of the important physics observed in associated laboratory micromodel experiments, including: embryonic nucleation, supersaturation effects, multiphase diffusion, bubble growth-migration-fragmentation, and three-phase spreading coefficients. The precise pore-scale mechanisms governing gas evolution were found to be far more subtle than earlier models would suggest because of the large variation of gas/oil interfacial tension with pressure. This has a profound effect upon the migration of gas structures during depletion and, in models pertaining to reservoir rock, the process of gas migration is consequently much slower than previously thought. This is the first time that such a phenomenon has been modelled at the pore-scale and the implications for production forecasting are thought to be significant.

Laboratory-Based Prediction of Sulphate Scaling Damage

BaSO4 scaling can have a disastrous impact on production in waterflood projects with incompatible injected and formation waters. This is due to precipitation of barium sulphate from the mixture of both waters, the consequent permeability reduction resulting in loss of well productivity. The system where sulphate scaling damage occurs is determined by two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient reflecting permeability decrease due to salt precipitation. Previous work has derived an analytical model-based method for determination the kinetics coefficient from laboratory corefloods during quasi-steady state commingled flow of injected and formation waters. The current study extends the method and derives formulae for calculation of the formation damage coefficient from pressure drop measurements during the coreflood. The proposed method can be extended for axisymmetric flow around the well allowing calculation of both sulphate scaling damage coefficients from field data consisting of barium concentrations in the produced water and well productivity decline. We analyse several laboratory test data and field data, and obtain values of the two sulphate scaling damage parameters. The values of kinetics and formation damage coefficients as obtained from either laboratory or field data vary in the same range intervals. These results validate the proposed mathematical model for sulphate scaling damage and the analytical model-based method “from lab to wells”. Introduction It has been long recognised that formation and well damage may be caused by incompatibility of injected and formation waters. Precipitation of salts results in permeability decline. Among the most significant of all scaling species are the sulphates, particularly barium and strontium sulphates. Decision making on scale prevention and removal is based on prediction scale precipitation and damage is provided by mathematical modelling. The mathematical models for sulphate scaling during waterflooding consist of mass balance equations for all species with the reaction rate sink terms. Chemical reaction rate must obey law of acting masses or another more complex kinetics law. Several numerical and analytical models describing sulphate scaling under laboratory and field conditions are available in the literature. Nevertheless, the problem of determining model coefficients from either laboratory or field data to use in sulphate scaling simulation is far from resolved. This SPE 100611 Laboratoryand Field Prediction of Sulphate Scaling Damage P. G. Bedrikovetsky, SPE, North Fluminense State University (LENEP/UENF); E. J. Mackay, SPE, Heriot-Watt University; R. P. Monteiro, North Fluminense State University (LENEP/UENF); P. M. Gladstone, Cefet-Campos/UNED Macae; F. F. Rosario, SPE, Petrobras/CENPES

Intergated Field Development For Effective Scale Control Throughout the Water Cycle in Deep Water Subsea Fields

SPE 94052 Integrated Field Development for Effective Scale Control throughout the Water Cycle in Deep Water Subsea Fields M.M. Jordan SPE Nalco and E.J. Mackay SPE Heriot-Watt U. Copyright 2005 Society of Petroleum Engineers This paper was prepared for presentation at the SPE Europec/EAGE Annual Conference held in Madrid Spain 13-16 June 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper as presented have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s).

Predicting Brine Mixing Deep Within the Reservoir and Its Impact on Scale Control in Marginal and Deepwater Developments

Sulphate scale deposition is a common problem in hydrocarbon reservoirs in which injection seawater that is rich in sulphate mixes with formation brines that are rich in barium, strontium, and calcium. Deposition of thesescales can cause significant production impairment if it occurs within zones near the production wellbores. To control scale deposition in the near-wellbore region of reservoir, scale squeeze treatments are commonly deployed. In cases in which scale severity is very high, removal of sulphate ions from the injection water is an alternative scale-control strategy. Both these mitigation methods have associated capital (CAPEX) (e.g., desulphation plant) and operating expenditures (OPEX) (e.g., scale squeeze treatments). To assess the severity of the problem in new fields, thermodynamic calculations typically are performed to calculate the mass of scale that will form. Until recently, little work has been carried out to identify the location of scale formation within the reservoir. In this paper, field data and flow simulations from three North Sea fields are presented to show that scale formation can, in fact. occur deep within the reservoir and can have a negligible negative impact on oil production in the near-wellbore region. Evidence is presented from these North Sea fields that shows the evolution of the brine chemistry as seawater breakthrough occurs and as squeeze treatments are applied. The evidence from the produced brine chemistry is linked to flow calculations for these fields to show that in some systems scale is depositing deep within the reservoir, reducing the potential for damage in the near-production wellbore region. The extent and impact of the deposition varies throughout the reservoir and can be quantified. Modeling brine mixing and stripping of the scaling ions before the fluids reach the production wellbore has a significant impact on the economic assessment of marginal fields and deepwater developments. In such fields, the technical challenge and cost (CAPEX/ OPEX) of scale control might make development uneconomical. This paper outlines the data requirements and methodology used to allow such an assessment to be made.