Successful Field Applications of CO2-Foam Fracturing Fluids in the Arkansas-Louisiana-Texas Region
Authors: Wamock W.E. , Harris P.C. , King D.S. 
Published: December 2007

Field experience in the Arkansas-Louisiana-Texas (ArkLa-Tex) area has demonstrated that CO2-foam systems can be used successfully in low-permeability oil and/or gas sands and carbonates at depths of 2,900 to 14,000 ft 1884 to 4267 m], reservoir temperatures of 120 to 370 deg F [48 to 188 deg ], and reservoir pressures of 1,000 to 13,200 psi [7 to 91 MPa]. Because of the high density of the psi [7 to 91 MPa]. Because of the high density of the water/CO2 mixture, CO2 foam can be used in deep, hot formations without prohibitive wellhead treating pressures. pressures.

Introduction

Hydraulic fracturing has been used to stimulate oil and gas producing wells since the late 1940's, and today it is considered a standard completion procedure on many wells that produce in the south Arkansas-north Louisiana-east Texas region. 1 Technology associated with fracture treatments has advanced significantly. particularly during the last 10 years. As the price of oil and gas has escalated, the application of many new fluids systems, proppants, etc. has become economically feasible, and proppants, etc. has become economically feasible, and many tight formations that formerly were bypassed as noncommercial are now producing significant reserve volumes.

CO2 has been added to fracturing fluids in various producing areas of the U.S. for many years. 2 Usually, CO2 producing areas of the U.S. for many years. 2 Usually, CO2 up to 500 scf/bbl [89 std m 3 /M 3 j fluid was added to assist in the post-treatment cleanup operations. In the late 1970's, CO2 was used initially in Texas at concentrations of up to 50% of the total injected volumes because of the associated improved fluid-loss efficiency and reduced total load water requirements. Foam fracturing with 70% CO2 as the internal phase of the fracturing fluid was attempted in the Ark-La-Tex region for the first time in early 1982. The field results to date indicate that the system has distinct advantages over more conventional gelled-water and nitrogen-foam fracturing fluids.

CO2-foam fracturing fluid (1) provides a gas drive to assist in removing (load) fluids after the proppant has been placed in the formation, (2) establishes permeability to placed in the formation, (2) establishes permeability to gas within the formation volume that has been saturated by load fluids, and (3) minimizes the actual water volume required to place a given volume of proppant in the formation.

The CO2 reacts with water in the foamto form carbonic acid, so that the overall pH of the system is reduced (thus reducing the damaging effect of the fluids), andto lower the interfacial tension of the load fluids so that they can be recovered more rapidly and efficiently.

Fracture Stimulation History

The Ark-La-Tex tristate area is characterized by sand or carbonate intervals with alternating shale sections from the surface to the Smackover zone at 10,000 to 11,800 ft [3048 to 3597 m]. A typical penetration to Smackover depth (Fig. 1) encounters more than 40 different zones that have produced commercially within the Ark-La-Tex region, and the more than 500 fields demonstrate that hydrocarbon sources, trapping mechanisms (usually structural anticlimes and/or stratigraphy), and reservoir-quality rock are present throughout this area. (Commercial production was first developed in south Arkansas, north production was first developed in south Arkansas, north Louisiana and east Texas in 1921, 1922, and 1927, respectively; however, the significant increase in gas prices in the late 1970's greatly accelerated the economic prices in the late 1970's greatly accelerated the economic development of the tight Jurassic zones (Cotton Valley, Haynesville, and Smackover) in many areas that had been identified years earlier.

Historically, low-permeability gas sands in the Ark-La-Tex region were successfully fracture treated with non-complexed, water-based treatment fluids to stimulate production. In recent years, most operators took advantage production. In recent years, most operators took advantage of the improved proppant transport and greater stability of complexed gel systems. If load recovery was considered a problem, CO2 often was commingled with complexed gels to aid cleanup. Recovery was enhanced further by use of 70-quality (70% gas by volume) nitrogen foams; however, increased wellhead treating pressures caused by hydrostatic head loss made treatment of deeper zones prohibitive. prohibitive. The Pettet Lime formation was stimulated primarily with acid treatments of various volumes, and acids often were gelled or foamed with nitrogen to increase formation penetration in fracture acidizing treatments. Fracture treatment with proppants was seldom used in the Pettet.

With the introduction Of CO2 foams to the area, many qualities of the complexed gel systems (i.e., improved proppant transport and good stability) were combined with proppant transport and good stability) were combined with the improved load recovery of nitrogen foams.

JPT

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