Oilfield Water Management Planning for Unconventional Oil & Gas Plays

With water scarcity a major concern of many oil and gas operators, new water management planning techniques and engineered water solutions are being developed that allow for produced water to be treated and reused to decrease fresh water consumption and disposal requirements in Unconventional Oil and Gas (“UCOG”) plays.  By satisfying a portion of oilfield water demands with reused production water, is it possible for operators, to reduce fresh water consumption while still reducing costs?  The answer is yes with the proper water management strategy.

UCOG plays (shale gas/oil, tight oil/gas, coal seam gas or coal bed methane, and water floods) require sourcing large volumes of water for hydraulic fracture completions and require handling part of the water load after the completion.  Development of UCOG is heavily dependent upon water because water is the primary constituent (generally making up over 98%) of a typical frac fluid.  Essentially, without water, hydraulic fracturing is limited and the development of UCOG slows. As oil and gas drilling and completion technologies advance in the UCOG market, operators are drilling longer horizontal laterals, fracing more stages, and using more ‘slick water’ fracing formulations. These factors all result in more water being used to complete an oil and gas well compared to just a few years ago.  For example, in the Niobrara Shale play of northeastern Colorado, operators were averaging approximately 70,000 barrels (“Bbls”) of water per well completion in 2012 and now they are averaging approximately 200,000 Bbls (8,400,000 gallons) of water per completion.  Additionally, some oil and gas wells are requiring over 400,000 Bbls (16,800,000 gallons) of water to complete.

In addition to water demand for hydraulic fracturing on the front end, there is excess oilfield water in the form of flowback and produced water that needs to either be disposed of in deep wells, reused by the industry, or treated and recycled for an alternate beneficial use.  Most UCOG wells produce 20 -30% of the completion frac load within the first six months of being opened up for production. Therefore, the operators have water management needs both on the front end and the backend of the well completion.

This dramatic increase in water needs, coupled with industry growth in historically dry areas of the United States (i.e. west Texas, southwest New Mexico, and Colorado), has resulted in oil and gas operators evaluating new techniques and technologies to develop fresh water resources and to increase the reuse of produced and flowback water within their overall water demands.  However, water needs prior to the completion and water handling after the completion is rarely managed by the same people within an oil and gas company.  Typically, drilling and completion groups evaluate water needs for the completion and the production groups handle the flowback and produced water after the completion.  To reduce total water costs and reduce needs for fresh water supply, the complete water cycle for the UCOG development needs to be strategically and tactically evaluated.  Strategic and tactical evaluation of water needs is of importance because of oil and gas price erosion over the past six months and significant reductions in capital spends.  As UCOG development continues and even increases, operators will be seeking overall water management strategies that are flexible, sustainable, and provide measurable improvement in capital and operational efficiencies.

Decreasing fresh water needs, increasing reuse of production water while keeping costs down can only be accomplished with the development of overall water management planning and strategy in the early stages of play appraisal.  Moreover, comprehensive oilfield water management solutions are required after the play appraisal and during the early stages of full field development to maintain the aforementioned goals.  The key economic criteria required to evaluate a UCOG water management plan are the cost and availability of source water; the types of water transport available and its associated costs; the types of disposal available and the associated costs; the type of overall management strategy used; and the available water treatment methods and their associated costs.  Oilfield water management planning and strategy development can define these criteria and eliminate unknowns.  For example, utilizing tools and expertise in water matters can allow for “what if” scenarios to be run to fully evaluate the water needs and limitations prior to the development of the field.  Issues that should be included are: (i) source water and disposal availability as impacted by regional geology, geography, and/or local regulations; (ii) the availability and cost of transportation and the impact of fuel prices, regional infrastructure, regional geography, and regional regulations; (iii) the cost and availability of treatment options as a function of the quality of water required for hydraulic fracturing, the flowback chemistry, and the state of the art of treatment technology; and (iv) industrial versus domestic activity in a region.

A robust, flexible, and intuitive water management decision support tool that has the ability to evaluate the operators’ water needs and all cost components, including flowback and produced water generation, can greatly reduce the uncertainty associated with water before and after the completion and provide the operator comfort that water needs are met at the lowest price possible. An example of how a field-wide water balance, calculated from a comprehensive water management tool, can quantify water demand, produced water volumes, available injection capacity, all as a function of time (all of which are critical to the field development process) is provided in figure below.