This study presents examples of fields operated by Total where are observed incompatibilities between reservoir formation water and injected seawater. In these examples, we show the scatter between risk estimated by modeling and site observations.
The prediction of calcium sulfate deposits identified by modeling is not valid as the scaling problems are either non-existent or considerably less serious than expected. With respect to the precipitation of barium sulfate, the risk estimated by modeling is always much higher than reality. In this study information are provided that will allow us to have more realistic scaling predictions in the future.
The injection of multiple chemicals, such as anti-scale and anti-corrosion additives, must often take place sequentially or simultaneously in very close injection points. Thus it is necessary not only to evaluate the efficiency of chemicals individually, but also to screen for incompatibilities and/or interference between chemicals. These interferences can affect either the anti-scale efficiency, the anti-corrosion efficiency, or even worth both additives efficiencies at the same time. This kind of mutual reduction of efficiency may have been the reason for past pipeline failures, where both scaling and corrosion were observed despite the addition of large quantities of both additives. Electrostatic interaction is a possible explanation, as the two chemicals carry opposite charges. In conjunction with the usual tests performed for additive selection, a physicochemical framework has been developed to evaluate the behavior of pairs of additives at different concentrations. For a model water presenting both corrosion and scaling issues, the efficiency of the anti-scaling additive is evaluated based on the quantification of free Ba2+ in solution by ionic chromatography and the efficiency of the anti-corrosion additive is assessed based on the change in the interfacial tension. Many candidate additives for oil field applications have been evaluated and "interaction maps" have been constructed. These maps indicate regions of concentrations at which one or both additives are not effective. These maps are useful for the selection of products that should be effective without risks of interactions. To finalize the validation, we can perform an "ultimate" blocking test where both additives, water and oil, are in contact at one point of the experiment, to also take into account the partitioning of additive between oil and water. This framework is not only useful for production chemistry studies of new field developments, but also for new product tenders in existing fields.
Large quantities of sea water are injected in oil and gas fields all over the world for pressure maintenance support and sweeping efficiency of the reservoir in order to maximize the hydrocarbon production. Many difficulties are linked with sea water injection such as risks of reservoir souring, loss of injectivity, incompatibility between sea and reservoir waters. One specific problem is the risk of sulfate based scale formation like barium sulfate. Indeed sea water contains around 2800 mg/l of sulfate and some reservoir contains high concentration of barium and strontium. If nothing is done to prevent the mixing of these two waters, scale deposits will occur at the producer wells once the breakthrough happened, with the loss of production.
One solution is to remove the sulfate from sea water prior to injection, and this is possible by using the nanofiltration process.This desulfation process based on membrane technology is in operation in TOTAL sites for more than 10 years and it works very succesfully.
This paper presents the feedback of ten years of operations both on the desulfation process and also on the scale prevention strategy. Based on the experience of three big desulfation units operated offshore on FPSOs, this paper presents the various parameters of this process such as the operational constraints, membrane cleaning requirements, need for efficient pre treatment, membrane life time, and efficiency in sulphate removal. Moreover at the beginning anti scale injection was installed on the producer wells to inhibit the residual sulphate coming from desulfation (40 ppm), however better efficiency of process and sulphate elimination in reservoir showed that this residual risk is nil. Results showed that the choice of desulfation is the best solution to prevent barium sulphate scale, even if this process can appear firstly as constraining and costly.
Barium sulfate, a nightmare
TOTAL is the operator of the Girassol, Dalia and Pazflor FPSO in Block 17 off the coast of Angola by between 800 to 1500 metre water depth, the operator of Alima FPU off the coast of Congo by around 600 metre depth. Each of these fields has numerous subsea production wells and numerous subsea water injection wells, for example Pazflor and Dalia have respectively 25 and 37 producers and 22 and 31 injectors. Oil production from these fields is around 700,000 Barrel Oil per Day (BOPD) and 600,000 Barrel of Water per Day (BWPD) with some wells having production as high as 40,000 BOPD. Pressure maintenance and reservoir sweeping by the injection of water is mandatory for these fields development.
Various sources of water for pressure maintenance can be envisaged. The use of water from an aquifer was rejected due to the cost of drilling and completing the subsea wells without any assurance that the aquifer would provide wells with sufficient rates and that the water found would be suitable for injection. The use of produced water is also considered. However, it was determined that there would be insufficient quantity, especially from the beginning of production. Consequently, seawater injection is a necessary source of water for injection, it is injected alone or in commingles with produced water, and for example Dalia has a water injection capacity of 405,000 BWPD for a sea water treatment capacity of only 230,000 BWPD. Pazflor and Girassol treated sea water delivery is even higher with respectively 300,000 and 400,000 BWPD.
The problem is that each of these fields has one or more producer reservoirs containing barium and strontium at high concentration typically around 200 ppm each. Mixed with the 2800 ppm sulfate of sea water this is the nightmare of producers.
We will first investigate the consequence of the incompatibility of the sulfated sea water and reservoir water containing barium. Then we will look at the possible solutions to solve the problem and mainly on the attractive nanofiltration membrane process. We will then analyse the result of more than ten years of operations of this solutions and how it evolves.
Baraka-Lokmane, Salima (Total E&P) | Hurtevent, Christian (Total S.A.) | Ohanessian, Jean-Luc (Total) | Rousseau, Guy (Total E&P) | Seiersten, Marion Elisabeth (Inst For Energy Technology) | Deshmush, Salim (Aker Solutions)
An offshore gas field located in the Far East has two reservoirs: reservoir A and reservoir B. Production fluids consist of gas and hydrocarbon condensate with some produced water from the two reservoirs. The producing fields are in water depths varying between 250 and 275m with ambient seawater temperatures and operating conditions that result in only occasional concerns about potential hydrate formation in the production systems. Lean Monoethylene Gylcol (MEG) is injected near the wellheads for hydrate inhibition.
This paper presents the risk of mineral scaling at critical points throughout the process with the three production scenarios: reservoir A alone, reservoir A and reservoir B, and finally reservoir B alone. Special attention has been put on the effect of mixing produced waters from reservoir A and reservoir B topside. Furthermore there are considerable uncertainties with respect to the amount of organic acids that may be produced; therefore some evaluations have been performed with and without organic acids.