Integrated water-management strategies explored in Scotland

Edinburgh, UK was the host of an SPE Applied Technology Workshop (ATW) dedicated to addressing the growing global challenges of effective water management in the oil field. Approximately 50 attendees representing production technologists and reservoir, processing, and petroleum engineers attended the ATW titled "Integrated Water Management: From Planning to Operations" and reviewed the latest technologies and strategies for maximizing value through improved water management at the field-planning and operational stages of an asset's life cycle.

Field-Planning Stage

Michael Hannan of the UK's Department of Energy and Climate Change (DECC) first discussed the regulator's role in reservoir preparation. He stressed that a regulator must ensure that an operator's field plans include processes for maximizing economic recovery factors and for complying with environmental laws. The DECC expects operators to have a thorough understanding of voidage and sweep in the reservoir and design wells and facilities such that recovery can be maximized.  The operator's plans should also be flexible enough to handle any unforeseen challenges associated with water handling. On the regulatory front for marine discharge of water, Hannan encouraged operators to keep abreast of future risk-based discharge limits being proposed by OSPAR—the northeast Atlantic convention that sets limits for marine discharges.

In his presentation titled "Planning Water Management," Owen Vaughan of Apache Corporation said that despite the importance of planning in effective water management, conflict may arise within an organization because planning has different meanings for different people, depending on their background and experience. He also discussed the impact of data quality on the planning process, saying that for greenfield developments the quantity of data may be insufficient to allow a comprehensive water-injection plan to be developed. Conversely, for brownfields there may be such a volume of data that much of its quality may be questionable.

A discussion followed amongst the attendees on the pros and cons of produced water reinjection (PWRI) vs. water disposal. Participants were asked to take a stance on one of the methods with no middle ground and then list the relative benefits of their method. Among the benefits that the proponents of water disposal listed were the abundant availability of affordable technology to allow for disposal at sea and the lower capital and operating expenditures involved. Reinjection proponents cited the positive environmental image of injecting water back into the reservoir from which it came, as well as avoiding the need to chemically and mechanically clean the water for discharge.

Another reinjection debate followed on whether to inject water above or below the fracture gradient. Those supporting injection above the fracture gradient pointed to the benefits of an easier-to-manage injectivity index, lower capital expenses owing to smaller pumping equipment, and design advances allowing for better sweep control.  Those arguing for injection in the matrix highlighted the benefits of a better injection profile, a diminished risk of vertical fracture propagation, and lower injection pressures resulting in better vertical sweeps.

The ATW's third session highlighted planning for water management during the production stage of the asset life cycle. Ewout Biezen, petroleum engineer with Shell, discussed some of the technologies and approaches to minimize water production in marginal-gas-field reservoirs. He specifically discussed monobore cemented completions for making marginal gas accumulation viable. In this simple concept, the reservoir openhole section completion tubing is run into the open hole and cemented back inside the previous casing shoe or window. In the event of bottom water and coning, the water is controlled with zonal isolation by setting a bridge packer in the lower part of the well. Biezen stressed that in the case of intermediate watered-out perforations, jointed pipe is the solution currently adopted.

Philippe Coffin of Total E&P reviewed the downhole separation technology under development by his company. He argued that produced water is on the rise globally, and more stringent regulation will obligate operators to use PWRI technology. Downhole separation has several benefits according to Coffin, among them less water to dispose, a reduction of surface water volume, increased oil production, and reduced environmental challenges. Some of the disadvantages include its limited applicability to only high water-cut wells, the need for an injection zone, potential fluid-compatibility issues, and the need for complex and costly separation equipment.

Antonio Luiz of Petrobras next discussed his company's efforts at implementing PWRI in the Campos basin as a means to counter the deposition of iron sulfide-containing deposits, commonly called "schmoo," in the pipeline between platforms. The three Petrobras offshore PWRI projects have demonstrated that water specification and injectivity decline are still challenges to overcome in a platform environment. These can be overcome by implementing fracture injection, special chemical products, coated pipelines, and filtration techniques. Luiz stressed the importance of monitoring water quality during any PWRI process, particularly for sand control and corrosion mitigation.

Operations Stage

Switching to water-management strategies during the operating life of a field, a session on water injection during operations used specific field case histories to highlight water quality. One field experienced severe declines injecting produced water, with variable-to-high oil content, into a shallow aquifer with high permeability and significant formation-fines content. The subsea context was important, with the subsea injection line having previously produced aquifer water and used for pressure support of the deeper oil reservoir. In a second example, an onshore field experienced slow injectivity declines in a very-high-permeability reservoir, but over several years reached 50% and climbing. The oil-in-water content was low (on the order of 20 mg/L), and solids were believed to be minimal. The same wells had previously injected shallow aquifer-sourced water with no injection decline. Injection conditions in both fields were below fracture pressure, and on backflow production the wells could recover good productivity.

"Filter bed" plugging effect of gravel packs or the formation would appear to be the culprit, particularly with higher oil content and solids that could be more prevalent in the subsea well. However, cumulative decline also occurred in the high-quality produced-water case, provoking the question of whether decline can be caused solely by accumulation from low oil content (~20 mg/L) or whether very low solids content also needs to be invoked. Potential treatment options discussed included conventional plugging and backflushing, similar to filter media; chemical treatment of the wells; injection above fracture pressure; and changes to the design of the well sandface.

Another field case demonstrated the importance of proper upfront investment to prevent future operational challenges. A marginal economics, or low capital investment, offshore processing facility was fitted with equipment that struggled to meet the operational specifications for injection water, which included both seawater and produced water. Plant and equipment failures were compounded by multiple fluid-treatment deficiencies, leading to oxygen corrosion, bacteria-induced corrosion, scaling, and erosion due to the presence of solids such as corrosion products and sand. This study demonstrated the importance of using more tolerant, flexible, and higher-cost processing equipment. However, this equipment may often require more maintenance. The study also stressed the equal importance of high standards for plant operation and monitoring to ensure that proper fluid specifications are maintained.

The final session of the workshop was dedicated to a field-study exercise in which attendees investigated the redevelopment of a field whose facilities were not adequate to handle the high water cut produced in the late stage of the field life. Attendees were split into four groups—facilities, injectors, reservoir, and producers—and each group was required to identify problems and provide solution and observations to be passed to other groups to achieve an integrated water-management strategy. While the separate teams were each given specific problems to address—such as limited pipeline and header capacity, corrosion and scale, and poor use of pumping equipment—they found commonality in their solutions. In the discussion that followed the separate meetings of the individual groups, the participants generally agreed that the main constraint for the mature life of the field was the excess water produced that could not be handled by the existing infrastructure, namely pipeline capacity.

The discussion also reinforced the common theme of the ATW, namely that it is crucial to have a multidisciplined project team at an early stage if the system is to cope with produced-water rates over the entire life of the field. Moreover, as water-rate forecasts are typically wrong, it is essential to oversize treatment facilities in early stages; in case water volumes are much higher than expected, upgrading facilities at a later stage is difficult and extremely expensive.

Ted Moon is the Technology Editor of JPT Online. He brings information on emerging technologies, R&D successes, new field applications, updates from SPE papers about recent innovations, and more. If you have a question or suggestion for future article topics, email Ted at teched@spe.org.