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Abstract The injection of seawater into oilfield reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature, operation. Moreover, the degree of risk posed by deposition of mineral scales to the injection and production wells during such operations has been much studied. However, the current drive within the North Sea to reduce the environmental burden of production chemicals and to reduce oil discharge to the environment has focused attention on the challenge of produced water management and has introduced new challenges for scale management involving produced water re-injection. This paper will outline the risk assessment process required prior to undertaking produced water re-injection. The factors that will be considered are the location of scale deposition around fractured and unfractured injection wells, formation damage potential and impact, and retardation effects on injected scale inhibitors. The paper will draw upon computer modelling techniques, laboratory generated coreflood data, and field results that will demonstrate the impact of the following factors on long term water injectivity: viz, scaling tendency, suspended solids content, suspended oil content, injection temperature, reservoir type, and completion type. Furthermore, scale control measures currently being employed (e.g., scale inhibition, hydraulic fracturing, drag reduction, and solvent cleaning) will be assessed and reviewed against the risks identified. Finally, this paper will outline in detail the particular scaling issues associated with produced water re-injection for both platform and subsea facilities. Introduction Increased environmental concern for the effects of produced water discharges is increasingly encouraging operators to dispose of produced water by re-injection either into the oil-bearing formation or into a specially selected aquifer. In addition to the environmental benefits of produced water re-injection (PWRI), there are other potential benefits including making cost, space and weight savings through the optimisation of water treatment facilities and produced water re-injection system throughout the life of a field. Re-injection of produced water is performed in several locations around the world. BP, for example, was an early adopter of the technology with re-injection schemes in Prudhoe Bay and the Forties Field in the early 1990's and the Ula Field in the Norwegian sector of the North Sea from the mid-1990's. Today, BP has a corporate goal of eliminating all discharges to the sea by 2004. Early experience of PWRI was focused on individual wells and did not include the co-mingling of produced water with seawater. With the move to full-field PWRI and the requirement to maintain voidage replacement, there is an increasing requirement to either co-mingle the fluids prior to injection or to inject both seawater and produced water into the same reservoir but via separate wells. Such practices introduce scale formation risks. These can be both calcium carbonate formation arising from the produced water itself and sulphate scales arising from the co-mingling of barium, strontium, and calcium containing produced waters with seawater. Clearly, the formation of such scales poses a risk to the topside injection system, the injection well itself, and finally the near-wellbore. Managing these risks is critically important to effective field management (in terms of being able to maintain adequate water injection) and to being able to maintain a zero water discharge commitment. This paper addresses methods of assessing the risk that scale poses to PWRI schemes and outlines the various management options that are available. The overall process and methodology is illustrated by field examples from the North Sea Basin. Risk Assessment Field Experience Under favourable operating conditions, the risk of scale damage to produced water re-injection wells should not be significant. However, it is possible that under certain injection conditions rapid build-up of scale could lead to complete loss of injectivity. Avoiding such a catastrophic scenario is the objective of the risk assessment process. The preliminary step is to study field case histories. This is then followed by the procedure of calculating potential scaling scenarios using scale prediction codes and fluid flow simulations to evaluate the risk. Field Experience Under favourable operating conditions, the risk of scale damage to produced water re-injection wells should not be significant. However, it is possible that under certain injection conditions rapid build-up of scale could lead to complete loss of injectivity. Avoiding such a catastrophic scenario is the objective of the risk assessment process. The preliminary step is to study field case histories. This is then followed by the procedure of calculating potential scaling scenarios using scale prediction codes and fluid flow simulations to evaluate the risk.
This is illustrated in Figure 1. of factors which may be difficult to diagnose. Some of these may center about poor inherent natural reservoir quality characteristics, others about mechanical considerations surrounding the condition and type of the wellbore obtained, and still others under the nebulous catchall of "formation damage" which often (and sometimes unjustly) absorbs the majority of the blame for the poor results of many projects. Formation damage in oil and gas wells is difficult to quantify in many cases. This is due to the inability of the reservoir engineer to retrieve exact samples and conduct detailed measurements on the area of interest, usually represented by a volume of rock surrounding the wellbore which is generally several thousand meters below the surface of the earth. However, ongoing research over the years has allowed the development of a variety of techniques allowing the use of the available information to obtain a much better indication of the type and degree of damage which different reservoirs may be sensitive to, thereby adjusting operating practices to attempt to minimize or reduce these permeability reducing factors. This data would include information such as production and pressure data, pressure transient data, log analysis, fluid and PVT data and core, cuttings, and special core analysis data.
Abstract Injection water-induced formation damage evaluation is considered critical in a low-permeability (2 md) oil reservoir development because of the potential bridging of narrow pore throats by in-situ scale precipitates. This problem can be mitigated with processed low-salinity water, albeit at significantly high capital expenditure associated with water processing facility that could erode the economic margin of the project. Laboratory fluid compatibility tests and software simulation were therefore conducted to appraise the risk of inorganic scale deposition during water injection in an undeveloped carbonate reservoir with high-salinity formation brine (TDS ~205 g/L). The laboratory experiments were initially carried out with both synthetic and actual field samples including formation water extracted from pressurized downhole fluid tester. Coreflood and fluid-fluid compatibility tests were carried out at estimated bottom-hole temperature of 150 °F and pressure of 1,000 psi. Comprehensive mixed-brine simulation software was also used to determine the inorganic scaling tendency expected with the use of seawater, produced water and diluted produced water for the planned injectors. The study identified an inherently high calcium sulfate risk associated with the planned seawater injection in the new reservoir while the highest combined inorganic scale precipitation was observed at approximately 1:1 ratio for the formation brine-seawater mixture. This paper discusses the laboratory fluid compatibility experiments and scale prediction analysis for different injection water utilization while providing an insight into the potential impact of scale risks associated with seawater injection in an onshore development reservoir with high divalent-salt content formation brine.
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Thomas, F.B. (Hycal Energy Research Laboratories Ltd.) | Imer, D. (Hycal Energy Research Laboratories Ltd.) | Ma, T. (Hycal Energy Research Laboratories Ltd.) | Schulmeister, B. (Hycal Energy Research Laboratories Ltd.)