A new method of completing multiple-layer tight gas wells is being investigated. The main concept is to place sliding sleeve valves in the casing string and complete the well with normal cementing operations. The sliding sleeves would then be opened one at a time to fracture layers independently without perforating. The possibility of high fracture initiation pressures is identified as the main risk with this approach.
This paper will discuss the theoretical and experimental study that was conducted to assess the viability of the cemented sliding sleeve concept by attempting to minimize and predict fracture initiation pressures.
Finite Element Analysis (FEA) was conducted to estimate the stresses in the cement and formation near the wellbore with sliding sleeve. FEA was used to adjust valve parameters that increased tensile stress in the cement and formation. Unstressed cement tests were then conducted on a variety of sliding sleeve valve shapes to verify the FEA study and to select the best valve shape.
Openhole and perforated casing fracture initiation pressures were calculated as a function of rock properties and far field stresses on the rock. An openhole condition was considered the best approximation to the opened sliding sleeve valve in regards to fracture initiation.
Full-scale stress frame tests were conducted using sandstone blocks with far field stress applied. The base case was set up using 4–1/2-in diameter casing cemented in one block and then perforated in the preferred fracture plane. Another sandstone block had a sliding sleeve valve cemented in place. Water was used to fracture these blocks and the fracture initiation pressures were measured. Good agreement between predictions and measurements was obtained, and the results indicated that high fracture initiation pressure is unlikely to be an issue with this completion method.
Perforating cemented casing is the most common method of completing vertical wells in multiple layer tight gas reservoirs. Jetting is another method replacing perforating, with a recent increase in popularity. These tight gas wells are typically stimulated with a proppant-laden fluid. When numerous productive intervals are present in the same wellbore, the wells are usually stimulated in stages. In each stage, a selected number of production intervals are perforated or jetted and then the stimulation treatment is pumped. After the stimulation, an isolation plug is typically set via wireline and then the next stage is perforated or jetted.
This method of treating multiple production intervals at the same time can result in less than an optimal treatment of the reservoir. The treating fluid downhole will be diverted into each layer depending on the resistance to flow. Depleted intervals, low pressure intervals, and intervals that fracture early will receive more than the designed amount of the stimulation treatment. The remaining intervals will therefore not receive the optimized treatment and well production will be less than optimal.
The industry is searching and experimenting with a variety of methods to stimulate each production interval independently to optimize gas production from each interval. The difficulty is to find a method that is efficient, effective, and cost competitive. The sequential opening of a single productive layer and isolating it from previously opened intervals requires a significant number of downhole operations. These operations are typically conducted by multiple interventions using slickline, wireline, or coiled tubing. Some of the new methods are placing more downhole hardware in the ground to reduce interventions. Other new methods are increasing the efficiency of these interventions by leaving hardware downhole during the stimulation treatment and moving the downhole hardware to the next layer without tripping to surface. Still other methods use diverter balls, sand, or other methods to provide temporary isolation.