The Effect of Completion Methodologies on Production in the Jonah Field

Abstract

Summary Improvements in completion technology have continued to increase the industry's ability to economically extract hydrocarbons from very low permeability reservoirs. The Jonah field in southwest Wyoming is a classic example of a reservoir commercialized with newer completion technology. The Lance formation in the Jonah field consists of several hundred feet of stacked lenticular sands with a reservoir permeability to gas of less than 10 mu darcy, requiring hydraulic fracturing to be economic. Completion techniques have evolved over the years. In the past 4 years, two techniques have emerged as the predominant completion methods - induced stress diversion and flow-through composite fracture plugs. This study evaluates these different techniques with spatial sampling to compare each well to its offset wells and to identify the completion scheme that yields the best results on cumulative production. From this study, a clear best practice for completing wells in the Jonah field to maximize production was determined. Introduction Jonah field is located in the northwestern corner of the Green River foreland basin (see Fig. 1), between the Wyoming Thrust Belt to the west and the Wind River Mountains to the east. The field is 60 miles north of Rock Springs, Wyoming. By the end of 2000, more than 200 commercial wells had been drilled on 40-acre spacing. The northeastern (downdip) edge of the field is still being extended. The known limits of the field currently exceed 38 square miles. The Jonah field is bounded on the south and northwest by two wrench faults. Faults within the field boundaries add to the complexity of the reservoirs. Wells within the field encounter overpressured gas at 8,100 to 9,300 ft (0.58 to 0.65 psi/ft gradient), whereas nearby wells drilled across the bounding faults find normal pressure gradients at similar depths. The Lance formation is Upper Cretaceous in age and consists of 2,000 to 3,000 ft of interbedded fluvial sands, mudstones, and coals. Individual sandstone units range from 5 to more than 50 ft in thickness and have areal extents ranging up to 100 acres. Individual sands are geologically heterogeneous reservoirs because of their depositional shapes, but certain stratigraphic intervals consistently have sands develop. Sand-rich intervals are locally called the Upper Lance, Middle Lance, Jonah, Yellow Point, Wardell, and Upper Mesaverde (or Rock Springs). Total net sand in the field ranges from 300 to 600 ft of stacked net pay. Drilling depths range from 11,000 to 12,500 ft depending on how many sand packages an operator believes to be economical to develop. More specific geological descriptions can be found in Refs. 1 and 2. The sand porosity ranges from 5 to 14% with relative gas permeability ranging from 0.001 to 0.02 md. Water saturation varies between 30 to 60%; currently, there is no significant water production in the field. The producing condensate yield is 8 to 10 bbl/MMscf with an API gravity of 52°. Pressure/volume/ temperature (PVT) fluid data are scarce, although the fluid composition appears to be very similar throughout the entire productive section. Because of the low permeability of the Lance formation in this area, stimulation is required for economical production rates. Although all operators use hydraulic fracturing for stimulation, there are a variety of different treatment types, fracture isolation methods, and times between treatments.3,4 Until 1998, the typical treatment consisted of treating three to six individual sands per fracture treatment with the limited-entry technique. A total of four to six fracture treatments were performed per well. After a fracture treatment, the well was flowed back for 1 week or longer to clean up. Several methods were used to isolate each fracture treatment, including pumping a sand plug to cover previous stages and running wireline-set tubing-retrievable bridge plugs. An integrated field study completed in 1998 showed that a common factor to all the operators was 60 to 65% completion efficiency.5 The study presented that the main cause of the low completion efficiency was damage to the hydraulic fractures as a result of methods used to isolate previous treatments in the wellbore. Since 1998, induced stress diversion became a common completion technique for some operators in the field, while other operators now use flow-through composite fracture plugs for fracture isolation. In both cases, the number of individual sands treated per fracture treatment has been reduced, resulting in more treatments per well. This study evaluates these new completion techniques as well as previous methods. Completion Types Traditional Completions. These include the use of sand plugs and wireline-set/tubing-retrievable bridge plugs. Sand plugs, which were the most common method in the early development of this field, are rarely used now. The most common early completion method used was wireline-set/tubing-retrievable bridge plugs. This technique was used with 30% nitrogen assist and 70% nitrogen foam fracturing treatments along with several non-nitrogen fracturing treatments. Induced Stress Diversion (ISD). This is a completion technique described by Hewett and Spence6 as an alternative to limited entry fracturing. ISD depends on two factors - stress increases with depth and closure stress increases when the fracture closes on proppant.7 To further assist in stress diversion, attempts are made to nearly "screen out" during the treatment by pumping higher proppant concentrations at the end of the treatment. This is done in an attempt to overcome high breakdown and treating pressures uphole. Because of the number of stages being pumped, it is also necessary to use some mechanical isolation. Because ISD requires increased stress from previous fracture treatments, it is a continuous process. One advantage to this method is substantially reducing completion time (2 to 3 days vs. 4 to 5 weeks), which results in significant savings in surface-equipment rentals and reduction in fracture-equipment charges. It is important to note that most of these savings can be realized if the well is completed in continuous stages even with the use of mechanical isolation between stages. Flow-Through Composite Fracture Plug (FTCFP). This is a new item in the composite downhole tools category. Use of FTCFP to isolate hydraulic fracturing treatments has resulted in improved production rates and increased estimated ultimate recoveries in several areas.8

A New Refracture-Candidate Diagnostic Test Determines Reservoir Properties and Identifies Existing Conductive or Damaged Fractures

“…With constant fracture half length during the injection and before-closure falloff, fracture volume changes are a function of fracture width, and the before-closure storage coefficient is equivalent to the dilating-fracture storage coefficient and written as 2 2 where S f is the fracture stiffness. 6 With equivalent before-closure and dilated-fracture storage, a derivation similar to that shown in Appendix A results in the dimensionless pressure solution written as 6…”