TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHydraulic fracturing injection experiments were performed in unconsolidated sand under stress to delineate the mechanisms controlling fracture propagation and to determine the effect of these mechanisms on potential formation damage. The tests included injection of cross-linked guar and visco-elastic surfactant into 3-Darcy sand samples subjected to different overburden stresses. The following observations were made:• The experimental data indicate that fracture propagation in unconsolidated sand is primarily a result of fluid invasion and shear failure in a process zone ahead of the fracture tip. The shear failure is caused by large tip stresses or by pore pressure increase within the process zone.• Three different invasion/damage zones were observed, including the external filtercake, the gel-invaded zone (or the internal filtercake), and the filtrate-invaded zone.• Sub-parallel "micro fracturing" and complex fracture geometry was encountered. The sub-parallel fractures may be initiated at the tip or at the fracture wall due to shear failure and is dependent on the fluid efficiency and the type of leakoff, i.e., wall building or viscous.• Field consequences of micro fracturing during stimulation may include early screenout, short fracture length and extensive formation damage as the fracturing fluid invades the sheared interfaces.• Typically, lower efficiency fluids were associated with increased net propagation pressure and higher density of micro fracturing.These findings suggest that injection of low efficiency fluids in weak, poorly consolidated formations results in a different type of formation damage, namely creation of sub-parallel micro fractures enveloping the main propped fracture, that could severely undermine post-stimulation productivity.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOffshore operators and service companies are increasing concerned about the environmental aspects of their offshore operations. Many offshore completions utilize "frac packing" as a preferred method to complete the soft formations found in the Gulf of Mexico. The frac pack operation manufactures and pumps large volumes of stimulation fluids from the fracturing stimulation vessel into the well. Most operations require at least two work string volumes of fracturing fluid to be reversed out and disposed of. This paper presents the development of a hydraulic fracturing fluid that not only met the oil and grease criteria established for well treatment fluids, completion and workover fluids; but how it was developed to meet the tighter standard established for the discharge of water based drilling fluids to comply not only with the letter of the regulations but with the spirit of the regulations.The service company specifications for the development of the low environmental impact fracturing fluid required not only it meet the oil and grease standard but also the toxicity standard for water based drilling mud and a biodegradability standard. The fluid development required it to meet the more stringent environmental standard, maintain its performance as a fracturing fluid and remain price competitive. The research process, the sourcing of new suppliers and the development of unique chemistry, with new patents, to accomplish the fluid development objectives are presented.The environmental performance of the fluid saves disposal costs, minimizes well site logistics and reduces risks associated of an accidental spill to both the operator and Service Company. A case history of the use of the fluid in an environmentally sensitive area is discussed and how the low environmental impact fracturing fluid system enabled the operator to discharge the fluid saving on disposal costs.
There are many advantages to using a single component, non-ionic viscoelastic surfactant gel (VES) for sand control and stimulation applications. The VES is highly compatible with a wide range of completion brines and crude oils, is virtually non-damaging to the formation and demonstrates shale-stabilizing characteristics with many types of shale. Another advantage of having a single additive VES system is that it requires a small equipment footprint. With this combination of compact equipment set-up and simplified fluid mixing, complex, high rate, high sand concentration frac jobs are possible where rig space is limited or equipment is limited because of the remote location from full stimulation service. A treatment using a single additive system can typically be performed with only one or two frac pumps, a frac blender, proppant silo or a modified sand infuser and data acquisition equipment. Many offshore facilities have commingled gathering systems many of which must be treated for emulsions with chemicals. This treatment process may be substantially reduced or simplified when a non-ionic VES fluid is used for stimulation compared to a crosslinked gel fluid. The high compatibility with completion brines and crude oils, coupled with the non-damaging nature of the VES itself, reduces the likelihood of formation damage in the well. The VES promotes a fast and more thorough recovery of the stimulation fluid from the formation and if emulsions are generated, it will allow for easier treatment in the surface facility. Since December 2000, non-ionic VES gels have been used in over 30 applications in the Adriatic Sea and in the Gulf of Mexico in brines ranging from seawater with varying amounts of KCl to 10.5 ppg CaCl2. Each application has resulted in enhanced production due to the excellent performance of the fluid. Clean-up rates have been directly related to bottom hole pressure, and have not been complicated with typical clean-up problems such as clay swelling, water blocks, and filter cake plugging of proppant packs. This type of treatment with a minimum equipment set-up has made high rate/volume frac treatments possible without the need of a stimulation vessel. Introduction The fracturing industry has focused on polymer-based fracturing fluids as their chemistry of choice for years1. The benefits of high viscosity and proppant placement have outweighed the disadvantages of formation damage and fluid complexity and sensitivity. Recently, polymer-free VES fluids have emerged as a possible alternative to the polymer-based chemistry2; however, compatibility issues between the VES fluids and various completion brines3 and with crude oils have caused some concern. New developments in VES technology have yielded non-ionic VES fluids that are highly compatible with completion brines and crude oils, without compromising their viscosity, proppant carrying capacity or non-damaging characteristics. These new generation VES fluids require only the base brine and concentrated surfactant for sufficient viscosity generation. The VES fluid can easily be mixed on a stimulation vessel using a standard blender setup, or on a rig from skid mounted equipment. The system requires a minimal amount of rig space due to its single additive design. Brine Compatibility Most polymer-based fracturing fluids are gelled in low weight brine such as 2% KCl4; however, the completion fluid controlling the well is typically a heavier brine. The compatibility of the fracturing fluid with this completion fluid is very important. Emulsion tendencies between the fracturing fluid and the completion brine would cause problems downhole. It is possible to gel polymer-based fracturing fluids in heavy weight brines and seawater; however, special formulas must be developed in order to offset the negative effects of the brine on the system5. An ideal fluid system would be one that is compatible with the completion brine.
Recently, advances in sand control completion practices have lead to the evolution and popularity of two different completion techniques: the high rate water pack (HRWP) and the frac-pack. A wealth of information has been published regarding each separate completion technique, but little information has been published on the direct comparisons of the two techniques. This paper describes three cases, from three separate fields, in which the HRWP and frac-pack techniques were employed. In each case, a completion was performed in formations with similar reservoir characteristics utilizing both the HRWP and frac-pack techniques. Completion steps for both the HRWP and frac-pack wells are discussed at the end of this paper. Production performance from each example is compared, as well as results from bottomhole pressure transient tests. System analysis is used in each case to compare completion effectiveness. The results are summarized with a brief economic evaluation of the two completion techniques for each case history. All three of the example sets presented in this paper consist of high permeability gas-bearing sands located in the Gulf of Mexico. Each example completion is from an area known to produce sand in large quantities if a successful sand control treatment is not performed. Introduction The examples that follow contain a brief description of the wells to be compared, along with a general description of the wellbore configuration and initial flow rates. A more detailed description of the frac-pack and HRWP completion techniques can be found at the back of this paper (Attachments 1 and 2). Table 1 contains the wellbore geometry and reservoir flow parameters for each case discussed in this paper. A comparison of well performance based on production rates, as well as a comparison of bottomhole pressure build-up data, is included for each well. In each gas well used in the following comparisons, a multi-rate test was performed in order to determine the turbulent coefficient associated with each completion. The analysis of the turbulent coefficient for each case history yielded interesting results. However, more conclusive results were drawn when the turbulent coefficients were compared by completion type. A brief discussion on the -system analysis results and potential productivity gains associated with each completion technique is included. Finally, a net present value (NPV) calculation was performed on each completion based on the cost associated with the completion, the production rates seen by each well and the forecasted production for each well. Capital expenses and first production were assumed to occur in June 1997. Expenses were forecasted based on each field's historical operating costs. Product prices were assumed to average $1.81/Mcf for 1997, $1.88/Mcf for 1998 and $1.92/Mcf for 1999. All net present values discussed in this paper will be discounted at 15%. A summary section will provide an overview of the data presented in an attempt to draw guidelines for selecting a completion technique of choice in sand control situations, based solely on deliverability. Other design considerations that are not discussed in this paper are the relative location of nearby fluid contacts (oil/gas, water/gas or water/oil), down hole equipment limitations and the dependability of the completion to control sand production. P. 269^
Mini-Frac Tests and Bottomhole Treating Pressure Analysis Improve Design and Execution of Fracture Stimulations S.J. Tinker, SPE, Pennzoil Exploration & Production Co., P.D. Baycroft, SPE, BJ Services Company, and R.C. Ellis, SPE, Pennzoil Exploration & Production Co., and E. Fitzhugh, SPE, Pennzoil Exploration & Production Co. Abstract Observations from fracture stimulations of 25 infill wells in the Grayburg / San Andres Formations at the Waddell Field in Crane County, Texas are discussed and presented. Micro-frac stress profile testing and mini-frac testing were performed to help design propped fracture treatments. Dead string pressure or bottomhole gauges were used for mini-frac and micro-frac testing. Tip-screenout methods were used to achieve desired proppant concentration in the fracture. Observations during treatments contributed to improved job design and execution. All but one well was equipped with a dead string during the frac job for observation of actual bottomhole treating pressure. Proppant transport problems detected in early treatments led to a change in fracturing fluid which allowed jobs to be pumped to completion. A wide range of leakoff characteristics was observed from well to well which made it necessary to include mini-frac testing as part of each stimulation. Large variations in measured leakoff occurred even in direct offset wells. Additionally, frac job fluid efficiency appeared higher than observed from mini-frac calibration work. The micro-frac stress test well provided a unique opportunity during the frac job to observe actual pressure in the fracture at a point away from treatment perforations. The fracture treatment communicated with the annulus through stress test perforations located above the packer. Pressure behavior observed in the fracture measured from the annulus was significantly different from pressure inside the casing at the treatment perfs. This paper presents data, observations, treatment improvements, discussion and conclusions concerning fluid selection, mini-frac and micro-frac testing, leakoff characteristics, and observations of pressure in the fracture. Introduction The E.N. Snodgrass lease is a 640-acre tract located in Waddell Field on the eastern margin of the Central Basin platform in Crane County, Texas. A map showing the field location is shown in Figure 1. The lease produces from an interval of about 300 feet in the Grayburg and Upper San Andres formations at a depth from about 3200 feet to 3500 feet. Production has been prolific and widespread from the Grayburg and San Andres dolomite formations in this area dating back to the 1920's. First production began upon discovery in the E.N. Snodgrass No. 2 in 1936. Offset development did not occur until the 1950's when 30 wells were drilled on a 20-acre pattern. Early waterflood activity began in 1967 with tour wells being converted to injection. Five successful workovers which included additional perforating and fracture treating were performed in 1993. Success of the workover program led to a 10 acre infill drilling program and full scale waterflood conversion program. Typical wells produce at rates of 40 BTFPD to 100 BTFPD. The completion and stimulation work on the 10-acre infill wells are discussed in this paper. The new 10-acre infill wells provided an opportunity to identify completion techniques that were most appropriate. A lease map with existing well locations and new infill wells is shown in Figure 2. One of the main challenges was to economically and efficiently fracture treat the 300 foot section of pay. Historically, this large interval had been fracture treated in three separate stages or by using limited entry technique with perforations throughout the entire pay interval. Mini-frac, step-rate, and micro-frac testing were all used to ensure the wells were completed effectively. Valuable and interesting observations were made during the completion program and are presented in this paper. P. 369^
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