Over the past 2 decades, unconventional development has focused on incremental gains largely from well-spacing strategies, completion chemistry, landing-depth selection, and extended laterals. Even so, there remain significant variances in production outcomes, including among wells drilled and completed with near-identical designs in comparable rock qualities.
Less attention has been paid to the influence of the compatibility of fracturing water. However, in recent years, extensive laboratory testing has helped researchers better understand how matching the injected frac water to a formation’s wettability, defined as being preferably oil-wet, water-wet, or neutral, may significantly increase initial production while also reducing produced water volumes.
Adjusting wettability, ideally to neutral, involves matching the formation-water salinity (i.e., total salt content).
This case study presents a procedure in which the operator compared production from wells with adjusted wettability to a control group, finding that the adjustments resulted in significant improvements in production and reductions in produced water.
A Challenge in New Mexico
In 2022, Silverback, a then-active private equity-backed producer in New Mexico’s Yeso formation, had been using fresh water for its hydraulic fracturing fluid. Two factors were prompting the operator to re-evaluate its methods.
One was that new regulations in New Mexico were restricting access to fresh water. The other was that the company’s production from early wells did not meet investor expectations. Additionally, some wells produced only water for up to their first 2 months, meaning their initial production (IP) was limited.
The company sought a way to re-evaluate its frac fluids to boost economics, both by improving initial and ongoing production and by reducing use of fresh water.
Field-Testing Procedure
The producer decided to divide the next round of new wells into two groups. The control group, consisting of 10 wells, would be fractured with fresh water, exactly as before. The test group’s eight wells’ wettability would be tested against a laboratory-researched database to determine if adjusting the frac water to match that wettability would improve initial and ongoing production.
The first round, evaluating the test wells for salinity-altering candidacy, showed that they would indeed be good candidates for adjusting wettability. An internal study based on client results shows this has been effective in about 70% of wells, and this testing has been shown to accurately evaluate which wells are good candidates.
At that point, more detailed tests were run based on oil and water samples collected from nearby wells, along with cuttings from an existing well.
Within weeks, the results came in, showing that produced water salinity and total dissolved solids (TDS) ranged from 100,000 to 120,000 ppm, compared with freshwater levels, which are a small fraction of that. The tests also showed that basing the fracturing fluid on produced water from other wells in the field would be the best first step.
Results of the Changes
Over the first year, the eight wells completed with formation water produced significantly better than the control wells. On average, the formation-water wells generated 14,244 bbl more than the control wells. Additionally, the formation wells produced 63,740 fewer bbl of water than the control wells.
On a percentage basis, the water-to-oil ratio improved by 27%. The IP for the first 90 days increased by 20% and was up by 31% over 180 days.
A significant question for the operation was whether the production increase would more than cover implementation costs. Below are those results and how they were calculated.
Assumptions: Freshwater total costs of $2/bbl, including acquisition, transportation, and disposal.
Oil prices: $60/bbl.
Resulting differentials over 1 year: Freshwater cost savings equaled $126,940. Increased oil production income equaled $854,650, and total dollar benefit averaged $982,119 per well.
Since these were horizontal wells, the results were adjusted to account for varying lateral lengths. Because of the reduction in produced water, costs of handling and disposing of water were reduced.
For any treatment, cost figures also include implementation expenses and payment to the service company.
Adjusting wettability for this test required only a few changes in the existing system. There was no heavy equipment and no need to purchase special fluids or chemicals. For the produced water, Silverback used stored water from a nearby pond.
The operator paid an agreed-upon fee per barrel, along with the initial testing costs, to the service provider
Explanation of the Mechanics
As stated, wettability refers to the preference of a solid surface to be in contact with oil, water, or both (i.e., neutral).
In a petroleum reservoir, it refers to the preferential adhesion of crude oil or reservoir brine to the formation rock surfaces. Matching the reservoir to the completion water can generate optimum wettability.
Historical Context
Prior to the invasion of drill bits and fracturing water, these reservoirs had been undisturbed, and their water (known as native, or connate), oil, and rock had been in chemical and thermal equilibrium for millions of years. Incoming frac water disturbs both.
The pressure upon entry exceeds the facture gradient and the completion fluid is forced into the rock’s pores, which were already filled with brine and oil. The frac water disturbs the equilibrium as it enters the rock’s pores and mixes with the trapped brine.
What’s produced is some combination of all of the above, including fracturing water, native water, oil, and gas. Additionally, there are natural surfactants from the oil.
Surfactants on the Rock
Oil surfactants, like soaps used at home, are water soluble. Some dissolve in the injected brine, some remain with the oil, and some cling to the rock. The distribution of these soaps determines wettability. Adjusting the water’s chemistry changes that distribution.
Randomly injected water can change the distribution of natural surfactants among the rock, water, and oil. Poor distribution can reduce the amount of oil available for production. The ideal placement is to have enough surfactant on the rock to reach neutral wettability. Switching to saltier water in the Yeso helped distribute sufficient natural surfactants onto the rock.
More surfactant on the rock makes it more oil-wet, and conventional thinking has been that the rock should be more oil-wet because that would release more oil. But there is an optimal amount of surfactant because making the formation too oil-wet can also limit production.
In petroleum reservoirs, the best results happen when the rock is neither oil-wet nor water-wet. Neutral wettability, where water and oil flow equally well, maximizes oil production and minimizes water production.
This has been proven in many studies in the lab and in the field since 1959 (Fig. 1). The new level of knowledge, as used in this case study and recently published technical work (URTeC 4264081), involves using salinity to adjust the wettability.
It is important to note that native surfactants differ from the chemical types injected with frac water, which are designed to lower the interfacial tension between oil and water and help them mix.
Conclusion
Testing a formation’s native wettability and using frac-fluid chemistry to improve performance proved to be a positive solution to predictably raise IP.
It boosted oil production, reduced water production (saving on disposal expenses), and cost little to implement. In the case study, the producer increased revenue by almost $1 million per well in the first year, and the positive effects of salinity matching continued well past 2 years.
Studies beginning in 1959 have proven this, but until now the oil and gas industry has lacked the tools to implement it in a robust and predictable way. As Tier 1 asset inventories continue to shrink, water matching may receive more attention and adoption.
Geoffrey Thyne, SPE, has over 40 years of experience in oil and gas, and is an expert in increasing hydrocarbon production by manipulation of water chemistry. Thyne began his career in the earth sciences in 1979 as a research geochemist at the Arco Oil and Gas research facility in Plano, Texas, where he was involved in projects in south Texas, California, and Alaska. He received his PhD in geology from the University of Wyoming in 1991 and taught at California State University-Bakersfield until 1996. He then joined the faculty at Colorado School of Mines. He returned to the University of Wyoming in 2006, where his work with the Enhanced Oil Recovery Institute (EORI) focused on carbon sequestration and enhanced oil recovery. During his time at EORI, he became immersed in the possibilities of changing water chemistry to improve oil recovery, intensively studying the process in both the laboratory and field. Thyne left EORI in 2012 and returned to the private sector at ESal LLC.