Doug Walser has extensive (31 years) Permian Basin, Mid-Continent, Appalachia, Rockies and South Texas experience with Dowell Schlumberger; The Western Company of North America; BJ Services; and Pinnacle, a Halliburton business line. He has specialized in the calibration of three-dimensional fracture modeling via a number of methods. Recently, he has specialized in the examination and comparison of the various emerging resource plays in North America, and more specifically, plays with liquid hydrocarbons. He has written 14 papers and holds three patents in his areas of interest. He can be reached at firstname.lastname@example.org.
The commodity price differential between liquid and gaseous hydrocarbons has been incredibly large for an extended period of time and is unparalleled in the modern history of exploration and production (E&P). Fundamental economic realities associated with a large domestic supply of natural gas and more restricted access to oil have combined to produce an investment climate that has not been observed during the last century. Though the future is always unpredictable, the current balance of supply and demand is stable enough that E&P companies are able to confidently target their long-term expenditures toward those activities that take advantage of acceptable margins for extracting oil. These same companies can maintain a reasonable expectation that natural gas commodity pricing will eventually improve to a point that it will make sense to develop and produce acreage that will yield primarily gas.
Meanwhile, the focus is on optimizing the recovery of liquid hydrocarbons from reservoirs that produce different hydrocarbons. The vast majority of active domestic (U.S.) unconventional plays targeted today produce a combination of three products: natural gas, oil (or condensate) and water. The implication, then, is that substantial incentives are present to direct development activities toward:
Minimizing long-term water production—Produced water is generally a byproduct of the process and must be disposed of responsibly or recycled.
Maximizing the rate of recovery of liquid hydrocarbons
Minimizing the impact of associated natural gas production—Rarely can the ratio of natural gas to oil (GOR) be controlled, so the objective becomes minimizing the cost of processing and transportation in such a manner that the negative fiscal impact of known low natural gas margins is minimized.
Substantial differences exist between unconventional reservoirs that produce primarily liquid hydrocarbons and those that produce primarily natural gas. Probably the most important is permeability. In the adaptation of Darcy’s law shown in Equation 1, it turns out that the ratio of permeability (k) to viscosity (μ) is important to well performance.
Q = the production rate
A = the exposed surface area
ΔP = the pressure drop from a given point in the reservoir to a fracture or the wellbore
L = the distance between the given point in the reservoir and the fracture or wellbore
Under normal circumstances, liquid hydrocarbons have between 50 and 75 times higher viscosities than most gaseous hydrocarbons. Because μ is in the denominator, the implication is that k must necessarily be higher to offset the restriction to volumetric flow imposed by the higher viscosity. Though many liquids-rich unconventional plays are currently being targeted in North America, the largest and most successful are those with higher overall permeabilities than the known existing unconventional natural gas plays.
The Williston Basin (Bakken), Delaware Basin (Bone Spring), Midland Basin (Wolfcamp) and the Eagle Ford Shale are all examples of scenarios in which the vertical lithological columns all contain mixtures of permeabilities ranging from millidarcy to nanodarcy in scale. The overall impact is often normalized values for k in the low microdarcy range.
During the past two to five years, the industry focus has moved beyond rank exploration and shifted toward the delineation of liquids-rich acreage with respect to recoverable reserves per acre. Up-front science expenditures have assisted in the determination of optimum parallel horizontal lateral spacing, optimum spacing of hydraulic fracture initiation along a given lateral, optimizing time between parallel completions, and optimizing short-term time between adjacent fracture stages.
Challenges to Lower Lifting Costs
As operators begin initiating manufacturing-mode operations that hold the promise of lowering lifting costs per barrel, some hurdles are noted:
Reservoir quality variation is an issue. When permeability is ultra-low (as in a typical natural gas play), then natural variability in permeability can often be offset by exposing more total reservoir surface area to conductive induced hydraulic fractures. In the case of the somewhat higher average permeability of liquids-rich plays, however, simply increasing the injected volume does not always solve the problem. With large variability in k comes imposed variation in parallel lateral spacing and spacing of induced fractures along a given lateral or series of laterals. Dissimilarity in total organic carbon (TOC), productive height and mineralogical content can also prove frustrating with respect to efforts to standardize drilling and completion processes.
The impact of a recent cross in supply and demand with respect to the pricing of natural gas liquids has taken the industry by surprise. Many liquids-rich plays contain acreage in which the primary in-situ reservoir fluid is a geologically immature, thermogenic natural gas. When the initially high pressure is dramatically lowered during production activities, different natural gas liquids can be produced. These include, but are not limited to, ethane (C2H6), propane (C3H8), normal butane (n-C4H10), isobutane (i-C4H10) and pentanes. Unfortunately, the transportation, processing infrastructure, and consumer and industrial demand in North America for these products have not kept pace with the abundant supply. The result is that in many liquids-rich plays, these natural gas liquids are selling for prices that are comparable to low-margin natural gas on an energy-equivalent basis.
The optimization process for a liquids-rich play is several times more complex than it is for a dry-gas unconventional play. Generally, a unique combination of up-front science, continuous reservoir parameter measurements and rigorous reservoir modeling is required to adequately characterize “optimum” spacing and process. When a reservoir hydrocarbon fluid system is composed of a mixture of under-saturated oils and saturated gas or a very rich gas that results in the production of condensate and/or large quantities of natural gas liquids, then accurate characterization of the hydrocarbon phase envelope is critical to production history matching and subsequent forward modeling efforts. Small errors in the construction of the phase envelope can result in large errors in judgment with respect to how well spacing and completion practices impact long-term net present value.
The extraction of liquid hydrocarbons from low-permeability unconventional reservoirs continues to present technical and fiscal challenges. The pace of technological breakthroughs impacting this effort is breathtaking, but operators and service companies that make efforts to focus on the integration of solid engineering and geological and geophysical concepts will likely succeed long-term.