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.
In order to assess scaling risk in pipes, a better understanding of scale deposition kinetics on steel surface under realistic and complex oil field condition is needed. In this paper, we introduce the development of a novel CaCO3 pre-coated steel tubing for studies of CaCO3 crystal growth kinetics and inhibition kinetics at oilfield conditions. This approach provides a relatively stable surface area and eliminates the limits of laboratory batch experiments. Initially, the heterogeneous precipitation rate of CaCO3 from a supersaturated solution (Calcite SI=0.3-0.7) was evaluated at specific temperatures (60-80???C), linear velocities (0.01-0.75 cm/sec), and ionic strengths (0.1-1M). The curve fitted heterogeneous precipitation rate constant, kppt, ranged from 10 -5 to10 -4 cm/sec. The results are comparable to that calculated from the Sieder and Tate equation, which indicates that the crystal growth was dominated by mass transfer rate. With the injection of scale inhibitors for one hour through the pre-coated tubing, the calcium carbonate precipitation can be prevented for days, and the crystal growth rate can be significantly slowed down. Not only does this study contribute to the limited data base of scaling kinetics in actual flowing pipes, but also provides a new approach to better understand the inhibitor reaction with the subsurface. The approach and results will assist in the prediction of scaling risk as a function of brine composition, well conditions and scale inhibitor composition, which will improve our ability to predict the severity of scale risk, including the rate of scaling, minimum blockage time, and thus the minimum inhibitory concentration needed in actual flowing pipes.
Silicate scaling is often induced by alkaline surfactant polymer (ASP) flooding in sandstone reservoirs. Scaling of the production tubing, rod or progressive cavity pumps, and other surface equipment causes frequent workovers, resulting in increased costs to the operator and non-productive time. The formation of silicate scale is complicated by its dependence on multiple factors including pH, silica concentration, and magnesium concentration, which vary as the flood progresses (Gill 1998). These factors affect silicate scaling tendency, and consequently, severity of the problem. Silicate scale inhibitors have been developed to mitigate problems in oilfields afflicted with silicate scaling due to ASP flooding (Qing et al. 2002). A new test method using an optical scanning device was developed to better characterize inhibition and dispersant qualities of the developed products on silicate scale in brine under static conditions. The advantage of this method is more comprehensive data generated by multiple-point measurements. Scaling reactions are more easily modified and differentiated. Water chemistries from several wells in an ASP-flooded field in Southern Alberta with known silicate scaling issues defined the tested synthetic brine. By allowing the mixed synthetic brine to react before adding inhibitor, the effect of delayed chemical injection may be studied. Performance of the tested inhibitor was significantly reduced by slight injection delay and may be attributable to the discrepancy between laboratory performance data and failures observed in the field. It is proposed that the performance of silicate scale inhibitors may be improved when applied by squeeze, where the inhibitor can inhibit silica polymerization within the formation and may provide substantial improvement over conventional continuous down-hole injection, where inhibitor reaches the water after the perforations.
Gomes, Roberto (Petrobras S.A.) | Mackay, Eric James (Heriot-Watt U.) | Deucher, Ricardo Huntemann (Petrobras) | Bezerra, Maria Carmen Moreira (Petrobras S.A.) | Rosario, Francisca Ferreira (Nalco Company) | Jordan, Myles Martin
Evaluation of the scaling risk at production wells is generally carried out using thermodynamic prediction models. These models are generally very accurate in terms of predicting the type of scale that may form, the degree of supersaturation, and
the mass of scale that will deposit by the time the system reaches equilibrium - provided the brine composition or compositions involved are well known, and the pressure and temperatures conditions are accurately specified. However, in
performing these calculations, engineers and chemists often fail to take account of reactions occurring in the reservoir, and assume that brines reaching the production wells have not reacted in any way prior to entering the wellbore. This often leads
to a significant overestimate of the scaling risk.
The work presented in this paper addresses this issue by studying data from various fields to identify what can be learnt from the produced brine compositions. A new technique to estimate the range of scaling tendencies that takes account of
reservoir precipitation is developed, and the results are displayed in a 3D response surface. This is illustrated for barium sulphate scaling tendency, accounting for different levels of ion stripping.
In order to calibrate some simulation parameters, and to identify the more important equations that should be inserted in the reservoir simulation, studies were performed based on the observed data. Different reservoir simulations were used and
compared, with a focus on scale management to identify positive and negative aspects of each one.
This work has identified that in fields with reservoir temperatures above 120°C and calcium concentrations above 7000 mg/l, significant sulphate stripping occurs due to anhydrite precipitation. This effect is increased where ion exchange
leads to a reduction in magnesium and an increase in calcium concentration as the injected brine is displaced through the reservoir.
Selle, Olav Martin (Statoil ASA) | Nygard, Ole-Kristian (Statoil ASA) | Storas, Elisabeth (Statoil ASA) | Moen, Arild (Statoil ASA) | Matheson, Rozenn (Champion Technologies Ltd.) | Juliussen, Bjorn (Champion Technologies) | Chen, Ping (Champion Technologies Ltd.) | Haland, Torstein Sleire (Champion Technologies) | Mebratu, Amare Ambaye (Halliburton Co.) | Melien, Ingrid (Halliburton Norway)
The success of chemical treatments to prevent or remove formation damage, depend on the placement efficiency. In down-hole scale control treatments, diversion techniques are applied for improved placement of scale dissolvers or scale inhibitors in the potentially productive intervals. Foamed scale treatment is a new diversion technology developed by the operator and two oil service companies. The new approach is to foam the scale inhibitor and scale dissolver solutions for improved placement of down-hole scale inhibitor squeezes and scale dissolver treatments. An additional benefit is that the gas used to create foam is perfectly suited for wells with low reservoir pressure and with no gas lift system in place. In theory the foamed fluid will enter the highly injective zones at a higher rate than the others so that the resistance to flow increases in the zones which have accepted the foamed fluid.
The technical qualification of the foamed scale chemicals was divided into advanced bottle tests and dynamic flooding tests. The first ever field application was performed in a Norne subsea well, under challenging weather conditions from an intervention vessel. Two subsequent pumping operations; one foamed scale dissolver and one foamed scale inhibitor operation were done. The post job evaluation concluded that the foamed scale treatments were successful and the technology is qualified for future use at the Norne field. The well became protected against scaling as seen from the scale inhibitor return curve, and the well came easily on stream following each treatment. The operational challenges were mostly in connection with wave height and vessel movement affecting the Nitrogen pumping stability.
The benefits seen with this technology are: it is a solid free system, it can be deployed by bullheading, the foaming agent is environmentally friendly and the system helps a quick post treatment production.
Sanders, Laura (University of Leeds) | Hu, Xinming (University of Leeds) | Mavredaki, Eleftheria (U. of Leeds) | Eroini, Violette (U. of Leeds) | Barker, Richard (University of Leeds) | Neville, Anne (U. of Leeds)
The formation of calcium carbonate scale and the occurrence of corrosion in CO2-saturated environments in different parts of oil and gas facilities are both phenomena that have been extensively studied. However, to date, very limited work has been carried out on evaluating combined products in a combined scale/corrosion methodology. This paper presents the results from a new combined bulk jar scaling/bubble cell corrosion test. The aim of this project is to investigate the effect of two combined chemicals in a new experimental setup; to study the corrosion and scale interactions which occur simultaneously. Two combined products were assessed at 5 ppm concentration at two temperatures (60ºC and 80ºC) in a CO2-saturated brine. Bulk scale precipitation was monitored using a turbidity meter and the corrosion rate measurements were made using the linear polarisation resistance (LPR) technique. Scale deposition and corrosion mechanisms have been studied using surface analyses. The performance of the two combined products has also been tested to measure: (i) the increase in the induction time of the calcium carbonate formation in the bulk, (ii) the change of the morphology of the crystals and (iii) the formation of a partial protective layer on the sample.
According to this study, the new experimental method has enabled the corrosion and scale deposition on pipeline steel (X65) and the bulk precipitation process to be studied simultaneously. Detailed scale deposition mechanisms on the material surface in the presence of corrosion processes and combined products are addressed from this study.
Keywords: calcium carbonate, scale, corrosion, combined inhibitors
Chen, Tao (Champion Technologies) | Heath, Stephen Mark (Champion Technologies) | Benvie, Ronald (Champion Technologies) | Chen, Ping (Champion Technologies Ltd.) | Montgomerie, Harry (Champion Technologies) | Hagen, Thomas Hille (Champion Technologies Ltd.)
The development of effective scale squeeze inhibitors in carbonate reservoirs is still a big challenge, especially with the increasing environmental constraints. For tight carbonate reservoirs, formation damage is one of the major considerations as it can be caused due to fines mobilization, carbonate reservoir dissolution and collapse, and scale inhibitor compatibility issues. For the development of any product for squeeze application, the product must also demonstrate good inhibition performance, long squeeze life and accurate residual analysis at low concentrations as well as being suitable for improved placement techniques if required.
Many scale inhibitors are either irreversibly retained in chalk reservoirs due to uncontrolled precipitation reactions or are poorly adsorbed with both processes resulting in short treatment lifetimes. Some new, readily detectable, polymeric scale inhibitor chemistry, containing a special functional amine group to have a good affinity to the chalk reservoir, was developed to provide a balance between irreversible and poor retention and thus provide effective squeeze life.
The results of a comprehensive testing program, including compatibility, formation dissolution, dynamic tubing blocking, static adsorption and core flood tests will be presented, that will highlight the design and development of a polymeric scale inhibitor suitable for tight carbonate reservoirs while meeting the environmental requirements for application in the UK and Scandinavia.
The new polymer has been shown to demonstrate excellent retention and release characteristics while also being non-damaging to carbonate reservoir material. The impact of calcium tolerance, pH and molecular chemistry will be discussed with regard to the design and performance of the new polymer when compared to some environmentally friendly phosphonate chemistry and other polymeric scale inhibitors.
This paper will demonstrate a logical design procedure to develop an environmentally acceptable polymeric scale inhibitor product whose chemistry has been optimised for squeeze application in tight carbonate reservoirs. In addition, discussions on the mechanisms of scale inhibitor retention and formation damage with regard to selection, design and optimization of suitable scale squeeze inhibitors in tight carbonate reservoirs will be addressed.
The mechanism of retention of scale inhibitors (SI) within the reservoir formation is central to a squeeze treatment having a long lifetime. Scale inhibitors are retained within porous media by the two main mechanisms of adsorption (G) and
precipitation (?). There is not complete agreement in the literature about when we should use one mechanistic description or another, and indeed both can occur together as coupled adsorption/precipitation (G/?). Previously a general model of
coupled (equilibrium) adsorption/precipitation has been derived and the agreement between the model and experiment was very good (Kahrwad et al., 2008). This model was subsequently extended to derive a consistent dynamic coupled G/? model for simulating non-equilibrium (kinetic) coupled processes of any type (Sorbie, 2010). This latter model has not yet been fully validated, but the work in this paper and its companion paper (Paper 2: Ibrahim et al, 2010) provides the type of data required in order to do this.
In this paper (Paper 1), new static experimental adsorption/precipitation measurements are presented for two phosphonate inhibitors, DETPMP (a penta-phosphonate) and OMTHP (a hexa-phosphonate) using sand, kaolinite and siderite as the
mineral phases. These experiments were carried out at a range of adsorbent mass (m)/ fluid volume (V)/ ratios and it is the "apparent adsorption??, Gapp vs. the final scale inhibitor concentration, cf, which is measured and plotted. By observing how
the Gapp vs. cf, curves vary for different values of the (m/V) ratio, this indicates whether we are in the purely adsorbing (G) or in the coupled adsorption/precipitation (G/?) regime (Kahrwad et al., 2008). For these static apparent adsorption tests, m =
10g, 20g and 30g samples of each mineral were used (with a fixed volume of SI solution, V = 80ml) to analyse the apparent adsorption behaviour. In addition, related pure precipitation/compatibility tests were carried out in the absence of any
minerals in the bulk solutions. The experimental results for both phosphonate scale inhibitors show good agreement with the theory in different regions of pure adsorption and coupled adsorption/precipitation. These results show clearly how such
laboratory measurements should be carried out to determine both the levels of SI retention and the precise retention mechanism. This paper characterizes the systems used in subsequent dynamic adsorption/ precipitation sand pack floods which are reported in a related paper (Ibrahim et al., 2012) and which will be used in future to validate fully dynamic coupled G/? flow models (Sorbie, 2010).
This paper will highlight the effectiveness of a novel, environmentally friendly multifunctional polymeric scale inhibitor that inhibits carbonate and sulfate scales as well as halite.
The deposition of halite in the oilfield can present a challenge for operators in fields with high TDS brines. The large amounts of halite that can deposit in a short amount of time can lead to reduced production as well as a costly and logistically cumbersome remediation. A customer was controlling halite deposition by injecting a low salinity water source to dilute/dissolve the deposits. However, this remedial solution also presented an additional problem to the customer as the injection of the fresh water source led to calcium carbonate deposition due to brine incompatibility.
This paper will present laboratory test results which highlight the effectiveness of this novel multifunctional scale inhibitor against halite, carbonate and sulfate scales. These results will be compared to traditional scale inhibitors. Following laboratory testing, this environmentally acceptable scale inhibitor product was deployed in high TDS wells where halite deposition was occurring. This paper will also demonstrate the successful implementation of the product, which provided calcium carbonate inhibition and a reduction in the volume of fresh water needed for control of halite deposition. This reduction in water consumption led to significant cost savings for the customer.
The value this case study brings to the industry is an overview of the challenges halite and associated scales present to hydrocarbon recovery and the development/implementation of a multifunctional molecule rather than a chemical blend for scale control. Results of this paper have implications for other fields across the world where halite scale is a flow assurance challenge.
For over a decade, being able to accurately predict the risk of calcium naphthenate deposition has been one of the goals of production chemistry studies for development of new fields. In order to fulfill this challenge, many studies have been performed both within the company and through collaborations in JIPs. These studies have also shown specific behaviours of acidic crude oil / water separation depending on processing conditions. They have also permitted the improved detection and quantification of tetraprotic acids that are one of the main building blocks of these deposits. In this work, we will show how these findings have been incorporated into a workflow used to quantify naphthenate deposition risk. In particular, we will try to illustrate how the "other" naphthenic acids of the crude oil can behave as an efficient natural inhibitor of the deposits, and why, even if tetraprotic acids are detected in quite a large number of oils, only a limited number of fields have faced large scale issues related to calcium naphthenate deposits, due either to "good" process design or good fortune. "Simple" physicochemistry tests turn out to be very powerful tools in order to assess the macroscopic behavior of the naphthenic acids, and their influence on the risk analysis.