First-Hand:Fracturing Recollections


Submitted by Tom Perkins

In 1957 I started working for Atlantic Refining Company (a predecessor company of ARCO, now BP). A strong recollection is that, in this company, all the early fracturing work was done without the aid of digital computers. The company did have a small, primitive computer, but it was reserved for the use of reservoir engineers. Those working in drilling and well mechanics, which included hydraulic fracturing, used slide rules. If a precision of more than about three significant figures was needed a mechanical calculator could be shared. Sophisticated mathematical functions such as logarithms or error functions had been developed by government agencies during the Great Depression and tables of functions were available in bound volumes in the library.

Probably Atlantic’s earliest work was the study of productivity increase resulting from vertical hydraulic fracturing of a solution-gas-drive pattern. The study was done with an electric analog model and resulted in a graphical portrayal of PI increase as a function of length of fracture relative to pattern dimension, and fracture conductivity relative to formation conductivity. This design graph was considered confidential but after several years of use, copies became generally available from our partner companies and service companies. Details of the study were published in a paper by McGuire and Sikora in 1960. This understanding of productivity improvement started us on the chase for higher fracture conductivity and longer lengths.

Higher conductivity suggested larger diameter and stronger propping agents. The need for larger diameters required an improved understanding of fracture widths. Not much was known initially about the mechanics of rock breakage at the leading edge of the fracture. Consequently for purposes of estimating fracture widths, a simplifying assumption was that the pressure in the fracture near the leading edge was essentially equal to the opposing earth stress. Later a series of papers reported (1) studies of energies needed to propagate the fracture through the rock, and (2) the effect of this breakage on the pressure within the hydraulic fracture near the leading edge.

The prospect of high conductivity via sparse propping led to two approaches. The first approach was to develop stronger propping agents. One of the earliest we developed was a ceramic-like, perfectly spherical, 1/8-inch diameter bead made from aluminum oxide. These spheres were very strong but expensive and about 30% heavier than glass or sand and thus hard to carry out to the end of long fractures. Wells in Oklahoma were successfully fractured with these alumina beads (usually tailing-in at the end of the treatment) using gelled-oil carrying fluid. Steel shot were used successfully in a west Texas well. The very strong propping agents such as these were very hard on pumps.

A second approach was to explore the use of ductile propping agents. Essentially spherical pellets of aluminum were obtained from two sources. When aluminum pellets were used to sparsely prop very hard formations, the pellets would yield plastically and flatten into disk shapes having large bearing areas against the rock face. Very high propped fracture conductivities could be measured with hard rocks in the laboratory. Several wells were fractured successfully, but others screened out. When propping material was bailed from screened-out wells, an unexpected problem was revealed. Many of the pellets were prematurely flattened, presumably under the pump valves, leading to too large a diameter and contributing to the screen out.

All large diameter and heavy propping particles are hard to carry to the end of long fractures. This led to early studies and a published paper dealing with solid transport in vertical fractures. As the volumes of fracture jobs increased, the need for a cheaper carrying fluids became evident. The use of a water-based fracturing fluid containing guar gum cross-linked with borate ion was invented by Mr. Loyd Kern. The first well fractured using this type of fluid was in west Texas; the fluid transported an aluminum pellet propping agent. The guar gum was obtained from a company that sold the gum for several commercial purposes including as a food additive. It was necessary to properly hydrate the gum before it could be cross-linked. On the first job, not much was known about the effect of field water quality on the hydration process. As equipment was being assembled for use in the fracturing treatment scheduled for the following morning, it was discovered that because of pH or perhaps because of ion content, the fluid refused to cross-link and gel properly. Frantic efforts during the night showed that re-acidification and adjustment of pH yielded good cross-linking. Tanks of fluid were remixed and adjusted properly just in time for the treatment to begin on schedule. The fracture job was successful. Cross-linked guar gum was on its way to being the great fracturing fluid we know today.

Fairly late in the development of hydraulic fracturing mechanics, an under-appreciated aspect was discussed in two papers in the mid 1980’s. Typically, injection pressures for secondary recovery projects were intentionally kept below fracturing pressures (which were known from fracturing of surrounding producing wells) so as to improve the sweep efficiency. I was asked to come to Alaska to discuss a belief of our field personnel that they were observing hydraulic fracturing of injection wells at pressures below surrounding producing wells in fields near Cook Inlet. I explained the conventional understanding of fracturing mechanics and that this was unlikely. Alternate possibilities were that fluid was being lost through a channel behind the pipe and into a thief zone. Years later when injection tests were conducted in preparation for sea-water flooding at Prudhoe Bay, similar injection behavior was observed. Finally the light dawned. Injection fluids are typically colder than reservoir temperatures. When a large volume of cold fluid is injected, contraction of the rock in the cooled region around the injection well leads to a reduction in earth stress and thus a reduction in injection well fracturing pressure. It was possible to quantify the magnitude of this effect and two papers were published showing that this effect can be of considerable significance during the injection of any fluid colder than reservoir temperature. The change of reservoir pressure in the vicinity of an injection or producing well has an analogous effect.

Our fracturing research work was seriously curtailed when prorating of oil wells led to other more economically attractive research opportunities. As the world demand for oil increased, the research and development of fracturing technology resumed several years later.