Abstract

Modeling a well's production response from a fracture stimulation design is a science. There are several commercial computer software packages that link fracture propagation models to reservoir simulation models. Data requirements to use these software packages include descriptions of fracture fluid behavior, rock mechanical properties, vertical stress distributions, and reservoir characteristics. There are many case histories that illustrate the adequacy of these models to predict economic outcomes. However, these models are not able to predict the production response resulting from the fracture (re)-stimulation where no input data is available. This particular situation exists for wells drilled prior to 1950.

Oil and gas development in the Texas Hugoton and West Panhandle Fields began in the 1920's. Many gas wells in these fields were originally stimulated with nitroglycerin or gelled naphtha and proppant Strip logs recorded by drillers and geologists provide most of the sub-surface information available in this area. A decision to initiate a stimulation and/or restimulation program for old wells in these fields would necessarily have to come initially from intuitive judgment. Results from the initial program cant be useful to help predict the outcome of future (re)-stimulation programs.

Presented in this paper are the results obtained from the (re)-stimulation of 62 gas wells in the Texas Hugoton and West Panhandle Fields. These results will provide a basis to model the uncertainty of (re)-stimulating similar old wells. The model relates the economic uncertainty to incremental production rate increases, incremental reserves and chance estimates when considering (re)-stimulation in the Texas Hugoton and West Panhandle Fields.

Introduction

Oil and gas exploration and development in Moore and Sherman Counties of the Texas Panhandle began in the 1920's, with the prolific Texas Hugoton and West Panhandle Gas Fields discovered while operators drilled approximately 3,000 feet deep to the Wolfcampian aged, Brown Dolomite formation in search of oil. Over the past seven decades these mature gas fields have typically produced 5 to 50 BCF per well, at an approximate well density of one well per 640 acres.

Texas Hugoton and West Panhandle Dolomite wells were typically drilled with a cable tool drilling rig and completed with open-hole sections. The earliest wells were stimulated with HCL acid or "shot" with nitroglycerin explosives, while hydraulic fracturing with "frac oil" or gelled naphtha was introduced in the 1940's. Advances in hydraulic fracturing technology in the 1960's allowed greater concentrations of proppant to be placed with waterbased, gelled fluids, and still later, wells were completed with carbon dioxide or nitrogen foamed fracturing fluids.

The cable tool drilling records included driller's and/or geologist's interpretation of rock cutting samples and significant gas production increases while drilling. In the absence of cores or wireline open hole electric logs, these driller's "strip logs" are the only available subsurface reservoir data.

With average bottom hole pressure of approximately 30 psia, the field is in a very advanced stage of depletion. Yet, the prolific dolomite reservoir allows the typical well to produce approximately 100 MCFPD and with relatively low exponential decline slope. The resulting decline curve extrapolations suggest substantial reserves and long producing lives remaining for these extremely old wellbores.

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