Field of the Invention
Embodiments disclosed herein relate generally to methods and control devices for production of consistent water quality from membrane-based water treatment for use in improved hydrocarbon recovery operations.
Background Art
Hydrocarbons accumulated within a subterranean hydrocarbon-bearing formation are recovered or produced therefrom through production wells drilled into the subterranean formation. When production of hydrocarbons slows, improved recovery techniques may be used to force the hydrocarbons out of the formation. One of the simplest methods of forcing the hydrocarbons out of the formation is by direct injection of fluid into the formation. This enhances production by displacing or sweeping hydrocarbons through the formation so that they may be produced from production well(s).
As shown in FIG. 1, a prior art system for recovering hydrocarbons from a formation consists of an offshore rig 12 connected to a well 10, which is completed in a subterranean hydrocarbon-bearing formation 14. Generally, fluid is injected directly into the subterranean hydrocarbon-bearing formation 14 (indicated by the down arrow) and forces the hydrocarbons through the formation and out of the well 10 (indicated by the up arrow) via a production well, which may be the same or a different well. One type of such recovery operation uses water (e.g., seawater, produced water) as the injection fluid, which is referred to as a waterflood. Water is injected, under pressure, into the formation via injection wells, driving the hydrocarbons through the formation toward production wells.
Injection water used in waterflooding for offshore wells is typically seawater and/or produced water because of the low-cost availability of seawater and/or produced water at offshore locations. Another motivation for using produced water as an injection water offshore is the difficulty in some locations in disposing the produced water offshore. In any case, seawater and produced water are generally characterized as saline, having a high ionic content relative to fresh water. For example, the fluids are rich in sodium, chloride, sulfate, magnesium, potassium, and calcium ions, to name a few. Some ions present in injection water can benefit hydrocarbon production. For example, certain combinations of cations and anions, including K+, Na+, Cl−, Br−, and OH−, can stabilize clay to varying degrees in a formation susceptible to clay damage from swelling or particle migration.
However, it has also been found that certain ions, including calcium and/or sulfate, present in the injection water may have harmful effects on the injection wells and production wells and can ultimately diminish the amount or quality of the hydrocarbon product produced from the production wells. Specifically, sulfate ions can form salts in situ when contacted with metal cations such as barium and/or strontium, which may be naturally occurring in the reservoir. Barium and strontium sulfate salts are relatively insoluble and readily precipitate out of solution under ambient reservoir conditions. Solubility of the salts further decreases as the injection water is produced to the surface with the hydrocarbons because of temperature decreases in the production well. The resulting precipitates accumulate as barium sulfate scale in the outlying reservoir, at the wellbore of the hydrocarbon production wells, and downstream thereof (e.g., in flow lines, gas/liquid separators, transportation pipelines, etc). The scale reduces the permeability of the reservoir and reduces the diameter of perforations in wellbores, thereby diminishing hydrocarbon recovery from the hydrocarbon production wells. Divalent cations are particularly effective at stablizing sensitive clays.
It has also been reported that a significant concentration of sulfate ions in injection water promotes reservoir souring. Reservoir souring is an undesirable phenomenon whereby reservoirs are initially sweet upon discovery, but turn sour during the course of waterflooding and attendant hydrocarbon production from the reservoir. Souring contaminates the reservoir with hydrogen sulfide gas or other sulfur-containing species and is evidenced by the production of quantities of hydrogen sulfide gas along with the desired hydrocarbon fluids from the reservoir via the hydrocarbon production wells. The hydrogen sulfide gas causes a number of undesired consequences at the hydrocarbon production wells and downstream of the wells, including excessive degradation and corrosion of the hydrocarbon production well metallurgy and associated production equipment, diminished economic value of the produced hydrocarbon fluids, an environmental hazard to the surroundings, and a health hazard to field personnel.
The hydrogen sulfide is believed to be produced by an anaerobic sulfate-reducing bacteria. The sulfate-reducing bacteria is often indigenous to the reservoir and is also commonly present in the injection water. Sulfate ions and organic carbon are the primary feed reactants used by the sulfate reducing bacteria to produce hydrogen sulfide in situ. The injection water is usually a plentiful source of sulfate ions, while formation water is a plentiful source of organic carbon in the form of naturally-occurring low molecular weight fatty acids. The sulfate reducing bacteria effects reservoir souring by metabolizing the low molecular weight fatty acids in the presence of the sulfate ions, thereby reducing the sulfate to hydrogen sulfide. Stated alternatively, reservoir souring is a reaction carried out by the sulfate reducing bacteria which converts sulfate and organic carbon to hydrogen sulfide and byproducts.
A number of strategies have been employed in the prior art for remediating reservoir souring with limited effectiveness. These prior art strategies have primarily been single pronged attacks against either the sulfate reducing bacteria itself or against a specific food nutrient of the sulfate reducing bacteria. For example, many prior art strategies have focused on killing the sulfate reducing bacteria in the injection water or within the reservoir. Conventional methods for killing the sulfate reducing bacteria or limiting their growth may include ultraviolet light, biocides, and chemicals such as acrolein and nitrates. Other prior art strategies for remediating reservoir souring have focused on limiting the availability of sulfates or organic carbon to the sulfate reducing bacteria.
More recently, strategies for remediating reservoir souring have included the use of membranes to reduce the concentration of sulfate ions in injection water. For example, U.S. Pat. No. 4,723,603 shows that specific membranes can effectively reduce the concentration of sulfate ions in injection water, thereby inhibiting sulfate scale formation. As taught by the prior art, nanofiltration (NF) membranes are often preferred to reverse osmosis (RO) membranes because nanofiltration membranes generally permit a higher passage of sodium chloride compared to reverse osmosis membranes. Consequently, nanofiltration membranes are advantageously operable at substantially lower pressures and operating costs than reverse osmosis membranes. Furthermore, nanofiltration membranes also maintain the ionic strength of the resulting injection water at a relatively high level, which desirably reduces the risk of clay instability and correspondingly reduces the risk of water permeability loss through the porous substrata of the subterranean formation.
However, in addition to the problems associated with sulfate ions being present in the injection water, it has also been found that the salinity of an injection water can have a major impact on the recovery of hydrocarbons during waterfloods, with increased recovery resulting from the use of injection water of lower salinity than natural seawater but sufficient ionic strength to prevent clay instability. Depending on the type of formation, injection fluids having higher salinity may cause the reservoir wettability to become more oilwet. This is because the multivalent cations in the brine, such as Ca+2 and Mg+2, are believed to act like bridges between the negatively charged oil and the negatively charged clay minerals that typically line the pore walls of the formation. The oil reacts with the clay particles to form organometallic complexes, which results in the clay surface being extremely hydrophobic and oilwet. As the oilwetness of the reservoir rock increases, hydrocarbons will adsorb onto the surface of the rock and thereby flow less easily from the formation, relative to water, which results in less hydrocarbon product being produced.
Lowering the electrolyte content (i.e., lowering the ionic strength) by lowering the overall salinity and especially reducing the concentration of multivalent cations in the formation reduces the screening potential of the cations. This results in increased electrostatic repulsion between the clay particles and the oil. Once the repulsive forces exceed the binding forces via the multivalent cation bridges, the oil particles are desorbed from the clay surfaces and the clay surfaces become increasingly waterwet. If, however, the electrolyte content is reduced too much (i.e., the formation fluid salinity is too low), the clay particles may be stripped from the pore walls (clay deflocculation), which will damage the formation. Thus, although it is desirable to have lower salinity injection water, it is important that the salinity levels be kept within a specified range.
Lower salinity water, however, is not often available at a well site. Lower salinity water is typically prepared, for example, by reducing the total ion concentration of higher salinity water using membrane separation technology (e.g., reverse osmosis). In known seawater desalination plants operating according to the reverse osmosis process, the seawater to be desalinated is subjected to a separation process by means of a semi-permeable membrane. Such a membrane is understood to be a selective membrane, which is permeable to a high degree to the water molecules, but only to a very low extent to the salt ions dissolved therein.
Membrane separation techniques used in the preparation of low salinity injection water use reverse osmosis (RO) membrane elements. Membrane separation techniques used in the preparation of low sulfate injection water and softened water use specialized nanofiltration (NF) membrane elements. The RO and NF processes use hydraulic pressure to produce lower salinity water from feed water through a semipermeable membrane. Depending on the membrane type, pressure and water conditions, an amount of salt also passes across the membrane, but the overall salinity of the product water is less than that of the feed water. Current RO technology can be used for desalinating both seawater and brackish water. The membranes used in the RO process are generally either made from polyamides or from cellulose sources.
The water to be treated is typically pretreated using cartridge filters, media filtration, microfiltration, or ultrafiltration methods, which are known to separate solids/particulates from the water based on their size. The water is then fed to the reverse osmosis and/or nanofiltration vessel using a high-pressure pump. The required pressure from the high-pressure pump is a function of the osmotic pressure, the temperature, the flux (i.e., the rate at which the water passes through a unit area of the membrane), and the volume of the feed water to be produced with a specific membrane area. The product water (i.e., the permeate) is discharged from the membrane module by way of a permeate conduit. A concentrate conduit serves for discharging concentrated ionic water.
Typically, conventional systems are only concerned with producing water having certain characteristics in amounts higher or lower than a predetermined level. Such systems focus only on a maximum allowable limit of a contaminant and treatment occurs as long as, and only if, the amount of the particular characteristic is above the set limit. Otherwise, the water is deemed acceptable for use. Most often, such a treatment plant will include several treatment blocks connected in series and/or parallel. In such systems, water is passed through as many of the multiple blocks, or through a particular block as many times, as is necessary for the particular characteristic in the water to reach the amount deemed acceptable for use.