Water Production

Key Takeaways

• Mechanisms of water production in oil wells include natural bottom water coning (where the drawdown pressure at the perforations creates a cone-shaped upward displacement of the water-oil contact toward the producing intervals), water channeling through high-permeability streaks or natural fractures (where the injected water in a waterflood or the natural formation water moves through preferential flow paths that allow it to break through to the producer faster than the average reservoir water advance), casing and cement failures (where micro-annuli or casing perforations allow water from external sources including shallow aquifers or injected water from adjacent wells to enter the wellbore outside the intended perforations), and production from perforations in the water leg (where the perforations extend below the water-oil contact because of incorrect completion depth placement or because the contact has risen to intersect the perforated interval during depletion): bottom water coning is the dominant mechanism in reservoirs with strong bottom water drives and vertical permeability high enough to allow vertical water migration to the cone shape at the production rate, and is characterized by early water breakthrough in the most productive wells (which have the highest drawdown and therefore the strongest cone driving force) followed by rapid increase in water cut after breakthrough; water channeling in heterogeneous reservoirs or waterfloods is diagnosed by tracer injection (a chemical or radioactive tracer added to the injected water and detected in the produced water at the producing wells), with short tracer transit times indicating fast flow through high-permeability channels rather than slow uniform displacement through the matrix.
• Water production management in mature oil fields requires a combination of reservoir management strategies (to minimize unnecessary water production that does not contribute to incremental oil recovery) and surface facility management (to efficiently handle the increasing water volumes at minimum cost): conformance improvement treatments (injecting gels, polymers, or cross-linked polymer systems into high-permeability channels in injection wells to divert injected water into lower-permeability zones that have not been swept) reduce water production by improving the sweep efficiency of the waterflood without shutting in injection; production rate management (reducing the production rate of high-water-cut wells to reduce the cone driving force or to allow wells that are intermittently producing above and below economic water-cut threshold to be managed selectively) defers water breakthrough and reduces the operating cost of the water handling facility; water shutoff treatments (mechanical plugs, cement squeezes, or chemical sealants applied in the producing well to block the specific perforation interval or fracture face through which the water is entering) are used when water is being produced from a specific interval that can be isolated and plugged without compromising oil production from adjacent intervals; the economics of each water management intervention are evaluated by comparing the cost of the treatment against the value of the oil production that would be deferred or lost to water production without the treatment.
• Produced water volumes in major oil-producing regions have reached enormous scales that represent one of the largest waste management challenges in the energy industry: in the Permian Basin (the largest oil-producing region in the United States), operators produce approximately 10 to 15 million barrels of water per day alongside approximately 6 million barrels of oil per day (a water-oil ratio of approximately 2 to 2.5 and rising as the fields mature), requiring a water disposal and recycling infrastructure of injection wells, pipelines, and treatment facilities that rivals in scale the oil production infrastructure itself; in conventional onshore US oil production overall, the average water-oil ratio exceeds 8 barrels of water per barrel of oil, reflecting the maturity of the domestic oil resource base; the cost of water production management (including the power for artificial lift to bring the water to surface, the surface facility operating costs for water separation and treatment, and the disposal costs for injection or discharge) constitutes 30 to 60 percent of the operating cost of many mature oil fields, and water production management is accordingly one of the highest-priority production optimization activities in the industry; the development of lower-cost water treatment technologies that allow produced water to be beneficially reused (for irrigation, industrial cooling, or as drilling and fracturing fluid) is a major area of research and commercial development driven by the growing scarcity of freshwater in the oil-producing regions of the American West and by regulatory pressure to reduce the volume of water disposed of by deep-well injection.
• Produced water chemistry characterization is essential for facility design and water management decision-making because produced water from different reservoirs can range from nearly fresh (less than 1,000 ppm total dissolved solids, TDS) to extremely saline (greater than 300,000 ppm TDS, approaching the solubility limit of sodium chloride in water), and the specific dissolved minerals, naturally occurring radioactivity, and organic content determine the treatment required for disposal or reuse: the major ion chemistry of produced water (sodium, calcium, magnesium, barium, strontium, chloride, sulfate, bicarbonate) determines the scaling tendency (the propensity of the produced water to precipitate calcium carbonate, barium sulfate, strontium sulfate, or other mineral scales as the water is produced from reservoir temperature and pressure conditions to surface conditions where the mineral solubility changes), with high-barium and high-sulfate waters being particularly prone to barite scale that can plug perforations, wellbore tubulars, and surface equipment; NORM (naturally occurring radioactive material) in produced water consists primarily of radium-226 and radium-228 (dissolved from the reservoir formation by the brine), which co-precipitate with barium sulfate scale when produced water is commingled with seawater or sulfate-bearing injection water, creating radioactive scale deposits in production equipment that require radiation safety management and specialized disposal procedures; the dissolved hydrocarbon content (benzene, toluene, ethylbenzene, xylene, and polycyclic aromatic hydrocarbons) of produced water determines the treatment required before surface discharge or agricultural reuse, with regulatory limits on these compounds typically being in the low parts-per-million to parts-per-billion range in jurisdictions that allow surface discharge.
• Artificial lift requirements for high-water-cut wells dominate the design and operating cost of production systems in mature oil fields because pumping a large water volume to surface from significant depths requires substantial electrical or mechanical energy that becomes the primary operating cost driver when the water-oil ratio is high: at a water cut of 95 percent (producing 19 barrels of water for every barrel of oil), the energy required to lift the fluid is 20 times the lifting energy that would be required for the same oil volume at zero water cut, meaning that the electrical power cost per barrel of oil at 95 percent water cut is 20 times higher than at zero water cut assuming constant production rate; electric submersible pumps (ESPs), beam pumps (sucker rod pumps), progressing cavity pumps (PCPs), and hydraulic jet pumps all see their performance and efficiency affected by increasing water cut, with most pump types requiring periodic upsizing as the water volume grows to maintain the required fluid lift capacity; the optimization of artificial lift type and operating parameters for high-water-cut wells involves balancing the pump operating efficiency against the cost of pump replacements (high-water-cut wells with corrosive produced water have shorter ESP run lives than low-water-cut wells), the electrical power cost, and the production uplift from increased fluid lift versus the revenue from the small fraction of oil in the high-water-cut production stream.