A full-cycle approach helps producers shrink an estimated US $40 billion water cost overflow.

Since water is the most abundant fluid in the majority of the world's oil fields, its incursion into the production stream - be it gradual or immediate - is a major factor in determining the productive and economic life of a field.
According to data supplied by Schlumberger, worldwide daily oilfield water production totals roughly 210 million for 75 million bbl of oil. That's a ratio of nearly 3:1; so water management is critical. In a well producing oil with an 80% water cut, the water-handling cost could be as high as US $4/bbl of oil produced. In some parts of the North Sea, water production is increasing as fast as reservoir oil rates are declining.
There is "good" water production, however, particularly when it aids in reservoir sweep and can be managed at a level below the water-oil ratio economic limit. Natural water drive and water injection are examples. But water production from whatever source ultimately is negative, since the money spent for control, shutoff and disposal lowers the production efficiency of individual wells and heightens overall field operating costs.
Philippe Enkababian, Schlumberger water control field support specialist, said the average industrywide operating expenditure for water production is an estimated $0.50/bbl. That amounts to an annual cost total of some $40 billion.
"And that's only an estimate of the direct cost of water," he said. "An even greater shortfall is incurred through the resulting loss of hydrocarbon production and decreased reserves."
Tackling the water cycle
The flow of water through a reservoir, into production tubing and surface processing facilities and its eventual disposal or injection for maintaining reservoir pressure is called the water cycle (Figure 1). The economics of water production depend on such factors as total flow rate, production rates, fluid properties like oil gravity and water salinity, and the water disposal methods chosen, Enkababian said.
Operational expenses associated with water production, including lifting, separation, filtering, pumping and reinjection, add to overall costs. Disposal costs alone can vary enormously, he said, with reports ranging from $0.10/bbl when the unwanted water is released into the ocean offshore to more than $1.50/bbl when hauled away by trucks on land.
Historically, operators have dealt with excessive water production reactively, said Enkababian. When water flow interferes with oil production rates, well owners seek to curtail or stop the water production altogether. In individual wells, such measures include procedures like squeeze cementing all or part of a producing interval; mechanical shutoff tools such as plugs and packers; and injection of shutoff or water-control gelling fluids. Additionally, the evolution of coiled tubing for well intervention has allowed operators to drill accurately placed lateral drain holes from the main well to stave off water incursion resulting from reservoir depletion.
Until recent times, said Enkababian, traditional approaches by service companies toward water system problems were made either at the reservoir level or at the surface and involved isolated products and services. Today, however, in keeping with the industry's acceptance of the total reservoir management concept, service companies have created teams that address the entire water cycle - from the reservoir to processing to disposal, he said. In the case of Schlumberger, it's the Water Solutions service, which uses a multidisciplinary approach to optimize oilfield water management. The goal is to enhance the value of oil and gas assets through reduced water-handling costs, improved hydrocarbon productivity and higher recovery factors.
Operators acknowledge that the key to water control is diagnostics, Enkababian said. And thanks to more powerful computers and software devoted to enhanced reservoir characterization and simulation, along with the ability to build knowledge bases - pools of accumulated experience - oilfield service companies are helping select the most suitable water solutions, for individual wells or entire fields.
Knowledge software
Jon Elphick, Schlumberger water solutions specialist, said a case-based reasoning (CBR) program allows more rapid and accurate identification of water-related system problems. Such programs also compare specific solutions to present to the asset manager for consideration and approval. Schlumberger calls its proprietary CBR program WaterCase.
Several service companies have developed water problem identification and solution options programs. However, Elphick said with CBR, the case base contains a pool of the accumulated experience of water specialists on a large number of water problems worldwide. However, it does not contain data on specific wells or fields, so there is no confidentiality issue.
But the pooled experience is valuable, Elphick said, only after the software-based methodology screens candidate wells on the basis of existing information such as production histories, existing production logs, reservoir characterization from numerical and analytical models and offset treatment data and experience.
"Once the problems have been recognized, the various solutions available to deal with the water issues are compared, using risk analysis tools and prediction of the impact on net present value," he said. "When the assessment is complete, the opportunities that have been identified, along with their predicted economic implications, are presented to the asset management team for approval. Those opportunities that are consistent with the asset managers' business objectives are then selected for complete evaluation and implementation."
Elphick said a typical case-based program interface asks specific questions about symptoms and diagnostic test results that help process analysis of the water problem. Once a sufficient set of information is available, problem types are identified and ranked according to their likelihood of incidence.
Singling out the candidates
A recent study provided by Schlumberger in the North Sea illustrated the results of the screening process offered with CBR, Elphick said.
There, a field contained nearly 100 wells with water cuts ranging from 20% to 90%, with a field average of 60%. Elphick said the scoping study made the following determinations:
• 15 wells were subsea, requiring a rig for intervention, and six had production tree or "fish-in-hole" problems, making intervention difficult;
• of the remaining 85 wells, 25 had corroded tubulars, increasing intervention risk;
• of the remainder, 25 wells had significant potential for additional productivity if the water cut were to be reduced; and
• of these, 15 wells had solvable problems consisting of casing leaks, flow behind pipe, bottom water, high-permeability layers without cross flow, or fractures from injector to producer.
The results, Elphick said, identified primary candidate wells to take through the second phase of the intervention process - developing a solutions plan. From there, mechanical, fluid and completion solutions were developed.
"The solutions spectrum was ranked by risk, cost and benefit using quantitative risk analysis," he said. "Solutions ranged from 'quick hit and rapid pay' to longer-duration 'high cost with higher pay' solutions." From that point, he said, Schlumberger worked jointly with the operator's asset team to identify the most cost-effective, lowest risk and highest value treatment option for each candidate well.
"Consequently, the chosen solution for each well was fully engineered for final submission and peer review prior to execution," said Elphick.
Finally, he said, to maximize fieldwide cost reductions, surface-related water services should be included in the screening process.
"An integrated solution is often a combination of borehole, reservoir-scale and surface systems," he said. "Surface facilities may contribute up to 25% reduction in overall water-handling costs."
What's ahead?
"Most water management is applied reactively to mature assets," said Elphick. "This is due to many factors, but primarily because there is a large number of mature fields that require immediate reactive attention. However, many water management principles can, and should, be used at the field development plan stage to optimize economic benefits."
However, if such "early" water management planning were to be adopted, it would have the potential to affect all parts of the field development plan, Elphick said. This would include:
• the producing well completion design to optimize vertical and areal sweep and avoid associated problems such as corrosion and scale;
• the location of producers and injectors for optimum areal sweep;
• the injection well completion to optimize vertical sweep; and
• facilities design to handle expected water throughput.
Meanwhile, he said, service companies continue to fine-tune existing water production diagnostics and management technology. And they are finding new water-related applications for tools originally designed for other uses.
A few of the recently enhanced technologies for reservoir-level diagnosis include reservoir and streamline simulation, 4-D seismic for water saturation mapping and database analysis and display systems, such as Schlumberger OilField Manager well and reservoir analysis software.
For individual well-level diagnosis, improvements include multirate production logging tools, production history analyses using diagnostic logs, downhole three-phase flow meters and water cut meters.
Additionally, through-casing resistivity logs - designed to locate bypassed pay behind pipe - are being used regularly to determine water saturation, particularly in large fields under long-time waterflood.
Finally, Elphick said much progress is being made in diagnosis and treatment methods. This is true not only for downhole water shutoff, but for all parts of the water cycle, including improved completions, surface facilities and reinjection. These improvements in water management can greatly improve the economics of mature fields, he said.

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