Steam generation for the purposes of thermal recovery includes facilities to treat the water (produced water or fresh water), generate the steam, and transport it to the injection wells. A steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells.

Desulfation of seawater before injection is required to control reservoir souring and scale formation. For this task, operators use nanofiltration (NF) membranes in sulfate removal units (SRUs). The tendency of the membranes to foul is a key operational challenge. To overcome fouling, frequent chemical cleaning is required. An additional constraint for SRUs is that the amount of treated water cannot be increased easily as a higher water output results in an even faster fouling of membranes. In this paper, we describe a method to enhance permeate flux and fouling resistance of desulfation membranes. The enhancements are achieved by modifying the active layer of commercially available NF membranes using a permanent coating that increases hydrophilicity while retaining the high surface charge characteristic of NF membranes. We report the results of a six-month field trial with the coated membranes. The test was executed at the Seawater Desalination Test Facility in Port Hueneme, California using 2.5" dia. membrane modules. The test skid contained two different parallel flow lines with a stack of six coated 2.5" dia. membranes in series, and an uncoated 2.5" membrane for reference. The results show a 25% higher permeate flux for the coated membranes compared to the uncoated membrane at the same transmembrane pressure. Sulfate rejection was unchanged for both coated and uncoated membranes during the entire duration of the test. The coated membrane also showed a lower fouling rate than the uncoated membrane. The time between cleaning events increased by ∼ 38 % for the coated membranes as compared to the uncoated membrane, and the coated membrane processed ∼ 63 % more permeate before cleaning was required. Preliminary results also indicate an enhanced chlorine tolerance of the coated membranes of at least 3000 ppm-h under continuous chlorination at ∼ 1 ppm. The impact of the coating on the economics of SRU operations will be discussed in the paper. The results presented in this paper demonstrate that performance and operability of SRUs can be significantly enhanced by a newly-developed coating, and that a significant reduction in the lifecycle cost of SRUs can be achieved.

Abstract The South Ratqa heavy oil field, located in the Northern part of Kuwait, will be developed thermally with the first phase of the development expected to become on stream in 2019. The water source to make up steam is coming from the Municipality Sewage Plant Sulaibiya (SWWTP) located in Kuwait City. The Sulaibiya plant is handling sewage water which is locally treated to make it suitable for further use. In the treatment process, RO units are used, and the reject stream of those RO units was identified as water source for the steam plant in the South Ratqa field. In total six steps are required to cover the full treatment scheme of the Boiler Feed Water (BFW) plant, namely: (a) Water Clarifier and sludge treatment, (b) Multimedia and Ultra filtration, (c) Ion Exchange, (d) double Reverse Osmosis, (e) Ozone and Ultra Violet treatment and (f) finally De-aerator. Currently, the plant is being constructed as part of the first phase of the South Ratqa thermal development. Control of bacteria was identified early in the design phase to be crital to ensure successful operation of the BFW plant with minimal down time. Bacteria control will be done at two locations: Upstream of the BFW plant: chemical control of bacteria growth with chlorine addition. Within the BFW plant: mechanical bacteria control using a combination of ozone addition and UV. Upstream of the BFW plant, chlorine will be added in the Sulaibiya plant located 123 km from the South Ratqa field. The project team realized that the added chlorine at this plant would not be enough to fully limit bacterial growth throughout the 123 km pipeline and more importantly, the growth in the 3 storage tanks upstream of the BFW plant. It was then decided to add extra chlorine injection capacity in the BFW plant just before the storage tanks. A suitable test protocol was developed to define the required extra chlorine demand resulting in a residual chlorine level between 0.5 and 2 mg/l entering the BFW plant and taking into account the extra residence times in the process. The extra injection capacity is currently under design. With the help of this extra chlorine addition bacteria growth will be under control and the required high BFW plant availability can be achieved.

Abstract One of the key challenges of the "A" West reservoir thermal development is the presence of an active bottom aquifer. If unmanaged, high aquifer pressures relative to the oil reservoir would have a detrimental effect on the ongoing thermal Enhanced Oil Recovery (EOR) process. Consequently, the "A" West development strategy includes an Aquifer Pump Off (APO) system. The key APO management objectives are:Lower the reservoir pressure and hence:a.Improve injectivity. b.Improve heat efficiency (more latent heat). c.Prevent quenching of the injected steam. Secure the feed water for the steam generation. In order to meet the above objectives, the following methods were used to evaluate the targeted pump off rate:Material Balance analysis. History matched full field model. History matched regional aquifer model, whereby several aquifer pump-off scenarios have been explored to further deplete the aquifer pressure in "A" West. A high APO capacity is initially required for an accelerated aquifer pressure depletion to match the currently low reservoir pressure caused by historical cold production of the upper half of the reservoir. This initial APO capacity is only required until the target aquifer pressure is achieved, after which, aquifer pump off rate will be gradually reduced to avoid oil cusping into the aquifer. To monitor oil cusping, water samples are collected from APO wells and facilities and analyzed for oil contamination. Moreover, three observation wells were drilled for real time reservoir/aquifer pressure gradient monitoring. These observation wells will also ensure an optimum pressure differential between the reservoir and the aquifer. The produced APO water is partly used as feed water for steam generation, with the remainder relocated to a shallow aquifer via a separate relocation system. To ensure oil free water, APO wells are located 100m below the OWC. In order to avoid well integrity issues and heat losses through the produced water, well trajectories have been designed to evade penetrating the steamed formation. An additional opportunity was realized by re-routing a portion of the excess water to a northern water-flooding project to maintain its reservoir pressure. This paper will focus on the integrated APO strategy, which meets the reservoir management objectives of the "A" West steam flooding project, and the PDO water management strategy.

ABSTRACT The extraction of Heavy Oil (HO) from the soon-to-be developed Lower Fares South Ratqa field requires steam injection to enhance HO recovery. The amount of water required for this facility is quite high, up to 210,000 barrels/day (in excess of 33 million liters per day), and the availability of suitable water is problematic, particularly in a dry country such as Kuwait. Enhancement of Heavy Oil (HO) recovery can be effected via cyclic steam stimulation and steam flood techniques. However, steam generation is highly dependent on the availability of sufficient quantities of suitable water. Potential water sources for steam generation include seawater, rivers, lakes or underground bodies of water. The last three are unavailable in sufficient quantities in Kuwait and specifically in North Kuwait. Seawater was initially considered as a source water option for the Lower Fares Heavy Oil (LFHO) project but further investigation identified another potential water source – a Reverse Osmosis (RO) reject water stream from the Sulaibiya Sewage Treatment Plant (SWWTP) – as a feasible option. After careful assessment, KOC selected the RO reject water stream from the SWWTP as the optimal solution. This innovative application utilizes a currently discarded resource and eliminates the environmental concerns associated with discharging this resource to the sea. KOC requires up to 210,000 barrels/day water to feed the Once-Through Steam Generators (OTSG's) to produce 80% quality of steam for injection into the wells. The water treatment technologies available in the market were evaluated to ensure that the RO reject stream could be successfully treated to achieve a suitable water quality for steam generation. The LFHO Project will utilize the SWWTP RO reject stream to enhance HO recovery in North Kuwait. The discharge of this stream to the sea is currently considered as an environmental concern. The use of this reject stream was previously not considered possible as no potential usage opportunities were identified. This paper covers the usage of this RO reject stream as the source water for steam generation for enhanced HO recovery. The use of RO treated water streams in the petroleum industry as make-up water for cooling water towers and cleaning applications is fairly common. The use of an RO reject water stream for steam generation to enhance HO recovery is a novel application for the petroleum industry. Figure 1: Utilization of Discarded Waste Water Stream for Heavy Oil Recovery:

Abstract To avoid hydrate formation, Kinetic Hydrate Inhibitor (KHI) is injected into the upstream wet gas pipelines. KHI eventually remains in the produced water which is treated for H2S and oil removal before it is re-injected into deep disposal wells. Industry regulators in the State of Qatar have concluded that the presence of KHI polymers in the injected wastewater leads to long term reservoir damage… Hence it is essential to remove KHI polymers from re-injected wastewater streams. As there are no industrially proven technologies for removal of KHI, pilot tests were conducted for removal via evaporation. At the same time, futher options were being assessed by other operators, including Wet Air Oxidation and KHI replacement with MEG. All options were assessed on technical, economical, planning, environmental, and safety criteria. The evaporation technology was found to be most suitable. The pilot tests showed that KHI can be removed via evaporation to produce a distillate stream, equal to more than 99% of the incoming flow, with KHI polymers residual concentration lower than the detection limit of 25 mg/l, which will be suitable for re-injection; plus a concentrate stream that includes the concentrated KHI polymers and other salts and solids. The process scheme was developed during the FEED (Front End Engineering and Design) stage, as follows. First, a pre-treatment step ensures breaking of the emulsions and the removal of oil and sludge. This mainly consists of coagulation and pH adjustment tanks, Dissolved Air Flotation and centrifuge packages. This is followed by a two-stage evaporator package which incorporates mechanical vapor recompression, cross heat exchangers, coolers, and cleaning in place techniques. Two outlet streams are created as a result; one distillate stream (free from KHI) which is sent for deep well injection, and one concentrate stream (with KHI), which will be sent to the concentrate storage facilities and will be loaded onto trucks for incineration by a third party. The removal of KHI from produced water streams using evaporation technology has never been done on an industrial scale. The success of this project would ensure that continuing the utilization of KHI products to avoid hydrate formations in the wet gas streams is suitable for the natural gas industry, whilst also avoiding any potential damage of the reservoirs in the long term.

Abstract This paper is based on work performed for Deepstar CTR11901 (for more information on the program see ). On average, only a third of in-place oil is recovered in Miocene reservoirs in the Gulf of Mexico. Water injection has been used to enhance the oil recoveries with limited success. Low salinity water injection could potentially further increase the oil recoveries achievable through seawater injection. For deepwater oil fields and those requiring long tie-backs to the existing host processing platforms, local subsea processing systems providing low salinity water injection could be useful in improving development economics. A Deepstar study has been carried out to evaluate the existing technologies for such subsea processing system to generate the low salinity from the seawater at 10,000 feet of water depth. Several conceptual process schemes have been defined and evaluated, employing various combinations of technologies, and compared from the point of view of operability, maintainability and technology maturity level. Technology gaps have been identified in the selected technologies and roadmaps have been defined to fill those gaps. The paper describes the methodology that has been used to review the existing technologies for water treatment and evaluate their potential for subsea application, presents the main results of the state of the art review and gives an overview of four process schemes defined for subsea implementation of a low salinity water injection station. Whole range of technologies for water desalination have been studied including membranes, electro-dialysis and the use of hydrate formation. The defined schemes combine desalination with other function technologies in order to optimize the make-up of the low salinity water to meet the particular reservoir needs.

Abstract 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.

Abstract In recent years there has been a shift in the Steam Assisted Gravity Drainage (SAGD) steam generation technologies from the traditional Once Through Steam Generator (OTSG) and lime based water softening towards the use of an evaporator and industrial High Pressure (HP) steam boilers. As a result, the available steam temperature and pressure exceeds the steam temperature that is required for injection into the underground formation. This excess steam enthalpy is the driver behind the steam generation method to be proposed. The method described is a revolutionary process for generating additional steam from highly contaminated oily water with an option for zero liquid waste discharge. The industrial boiler superheated steam is used as the driving force for generating additional steam in a direct contact heat transfer with the contaminated water. Fine Tailings from tailing ponds can be also used. The presented technology generates a "tailor made" pressure and temperature steam, as required for injection into the underground oil bearing formation. This newly developed technology allows generation of additional lower temperature steam from waste water in a high efficiency energy process. The simulation results show that an additional 8% – 24% steam (on a mass basis) can be generated from highly contaminated oily water. The amount of additional steam generated increases with the temperature of the driving steam, and with the reduction of the pressure of the formation. For low pressure shallow formations, additional steam can be produced in comparison to deep, high pressure formations. Another option is to recycle a portion of the produced steam through a heater and use it as the driving steam, and by that minimizing the need for external steam as a heat energy source. A portion of the oil component in the water feed will be converted into hydrocarbon gas that is expected to show similar behavior to a solvent. Additional solvents can be added and injected with the steam to improve the oil recovery. The presented technology has a high thermal efficiency capable of consuming contaminated hot produced water, without the need to reduce their heat to allow effective water treatment. The technology "fits" in the gap between the HP superheated steam and the injection steam while allowing the producers to maximize the advantages and benefits from the use of evaporators and steam boilers for SAGD oil production and can convert the existence of oil contaminate within the feed water into an advantage by replacing the solvent. This steam generation direct contact facility can be located in close proximity to the SAGD pads to use the hot produced water and inject the produced steam into the injection wells.

To "push" water impurities toward the tail of your Steam Generator where exchanged heat flux is low, this is the main purpose of the Multi-Circulation concept. This is done by design with Once Trough Steam Generator (OTSG) while for water tubes drum boilers (WTD) impurities concentration in boiler water remains constant from boiler entrance (furnace side, with high heat flux and high flue gases temperature) to boiler tail (exit side with low heat flux and low flue gases temperature). Refer also to Fig 1 Both of these boilers are water tubes type: water & steam side is tubes side. One other main specificity of OTSG boiler is also that water volume ratio decreases from 100 % at tube entrance (furnace side typically) down to 2 or 3 % -typical for 100 bar pressure - at tube exit (boiler exit typically) (Refer also to Fig 2); so such boilers can be subject to inside tubes fouling when salinity is too high and / or blow down rate is too low. You have to make arbitration between maintenance costs and water & energy costs varying in opposite way by selecting the right boiler blow down rate. Boiler yearly availability is also a consequence of this decision. For WTD boilers, water volume ratio is quite constant from entrance to exit as for this kind of boiler, natural circulation is controlled by design; operator has no impact on this parameter for a boiler operated within it normal design range. These boilers are then less subject to tubes fouling but water characteristics are more stringent. Of course boiler tubes fouling are mainly depending on feed water quality - so on water treatment system - and on boiler characteristics such as water volume ratio, heat flux and salinity level. When salinity concentration increases and when water volume ratio is low, fouling risks by deposits are then max. With some salts such as Silica having a low thermal conductivity, even very thin deposits have a great impact on tubes wall temperature leading quickly to tubes failures if they are in hot flue gases (furnace side). Regarding these parameters each boiler type is different and then boiler shall be selected carefully considering advantages and inconvenient of each type. Then, if you have to operate your boiler with low quality feed water and high availability rate we would recommend you prior to select one of two well know boiler type - OTSG or WTD - to consider a third type: the MultiCirculation Steam Generator (MCSG). The Multicirculation, what is that? A kind of OTSG / WTD hybrid: a WTD design slightly modified to include one OTSG main characteristic: variable boiler water salinity from inlet to outlet. Then this MCSG boiler has advantages of both types: Low Feed water quality, low blow down rate, high water volume ratio and then and Low Fouling risks. (Refer also to table 1). Heating surfaces of a MCSG boiler are then subject to or highest heating flux and lowest water salinity, or lowest heating flux and highest water salinity