Optimizing Spacing of Multistage-Fractured Horizontal Wells in Gas Reservoirs
The growing demand for gas in Saudi Arabia and the availability of multistage-fracturing (MSF) horizontal-well technology have spurred the development of tight gas reservoirs throughout the country. Draining the reservoir efficiently by use of MSF strongly depends on well spacing, especially for low-permeability reservoirs. This paper gives the recommended MSF horizontal-well spacing for several development scenarios in Saudi Arabian gas-reservoir environments.
Theoretical Background
There are four different flow regimes for multiple-fracture systems without wellbore storage: early linear, early radial, formation linear, and pseudoradial flow (Fig. 1). The initial flow period observed is the linear flow, where fluid flow toward the fractures in the formation is perpendicular to the fracture planes. This flow exists when each fracture behaves independently and most of the fluid entering the wellbore comes from the fractures (when the fracture-tip effects have not yet affected the pressure behavior). After the start of the flow into the fracture tips, the early radial flow develops while there is still no communication between fractures.
This flow regime may occur briefly or it may not occur at all, depending on the fracture length and spacing. Subsequently, formation linear flow develops after the fracture interference has been felt and the flow becomes normal to the horizontal well. Finally, the pseudoradial-flow regime develops in the formation, where the flow appears radial toward the entire well/fracture system. During this flow period, the composite fracture system behaves as if it were a single fracture. The flow eventually will reach pseudosteady state when it hits the reservoir boundaries or interferes with surrounding wells.
The rate at which the flow regime develops, from the start of production under transient conditions until it reaches reservoir depletion under pseudosteady state, is highly dependent on well spacing and well and reservoir characteristics.
Methodology
A major advantage of using a reservoir simulator is the ability to predict production resulting from various reservoir and fracturing scenarios; however, this requires performing an excessive number of simulation runs to cover all possible scenarios. To narrow the problem, sensitivity runs of different reservoir and fracture parameters are performed first to provide insights on the effect on production rates and cumulative production over 20 years. Subsequently, critical parameters were selected on the basis of sensitivity results to reduce the number of models to be simulated. The parameters that were varied in the models include reservoir permeability, formation thickness, and vertical-to- horizontal anisotropy, as well as variations of fracture properties.
Model Description
The reservoir-simulation models used in the sensitivity and optimization studies are almost identical, with the only difference being the grid size. The objective of the sensitivity study is to identify the parameters influencing gas production from horizontal wells. The effect of reservoir and fracture parameters needed to be studied on an infinite reservoir to eliminate the reservoir boundary effect on gas production. Grid design is detailed in the complete paper.
In this simulation study, openhole multistage-fractured horizontal-well completion was modeled, where gas is assumed to be flowing into the well-bore through both fractures and the horizontal-well section. Only transverse fractures were considered because they were proved to be the most suitable for tight gas reservoirs. Non-Darcy flow was also modeled in this study to describe the additional pressure drop at the wellbore.
The study investigated well spacing in low- to moderate-permeability gas reservoirs of 0.01, 0.1, and 1.0 mD; reservoir thickness of 30 and 100 ft; and vertical-/horizontal-permeability ratios of 0.01, 0.1 and 1.0. The optimized well spacing was evaluated for several fracture half-lengths to cover the possibility of having short fractures created by acid fracturing and long ones created by proppant fracturing. The numbers of hydraulic fractures considered were three, six, and 12, corresponding to fracture spacing of 880, 440, and 220 ft, respectively.
Distinct well-placement configurations were considered in each case. To efficiently drain the modeled reservoir with an area of 10,560×10,560 ft2 and with 3,000-ft-long horizontal wells, the needed number of wells placed in the x-direction was two, four, and six for reservoir-permeability values of 0.01, 0.1, and 1.0 mD, respectively. Only the distance between the wells in the y- direction is optimized.
Sensitivity Analysis
Reservoir Characteristics.
The sensitivity of cumulative gas production from horizontal, multistage-fractured wells to three reservoir parameters (reservoir permeability, formation thickness, and vertical-to-horizontal anisotropy ratio) was evaluated. There is a significant difference of drainage area and cumulative gas production in reservoirs with different permeability values. Horizontal wells drilled in 1.0 mD reservoirs drain larger gas volumes over the course of 20 years of production time, compared with wells drilled in 0.01 mD reservoirs. Reservoirs with low permeability normally take a longer time to deplete compared with highly permeable reservoirs. Higher-permeability reservoirs are thereby expected to require fewer wells or have larger well spacing to drain the reservoirs efficiently over 20 years.
In addition to varying reservoir per-meability, formation thickness was varied to examine the effect on gas production. Results suggest that thickness has no significance on cumulative gas production in an infinite-acting reservoir.
Fracture Characteristics.
Permeabilities in the neighborhood of 0.01 and 1.0 mD were considered in the sensitivity models. Results indicate that a higher number of transverse fractures results in a higher cumulative gas production than is seen for a lower number of fractures. This relationship between cumulative production and the number of transverse fractures is more pronounced in 0.01 mD reservoirs than in 1.0 mD reservoirs.
Similar behavior is observed when modeling gas production from horizontal wells with short and long fractures in reservoirs with different permeabilities. Larger cumulative gas production is obtained from horizontal wells with longer fractures, and the effect of fracture length on production is more noticeable in tight reservoirs. Horizontal wells drilled in moderate- to high- permeability reservoirs are expected to need the same optimum spacing regardless of fracture properties. This indirectly indicates that MSF horizontal wells in high-permeability reservoirs may not add significant increase to the ultimate gas recovery. Therefore, this conclusion is applicable only under the assumptions of dry gas and a homogeneous reservoir and should not be generalized.
Well-Spacing Optimization
Well Spacing vs. Reservoir Permeability.
The reservoir-permeability values considered were 0.01, 0.1, and 1.0 mD, which represent low- to moderate-permeability reservoirs in Saudi Arabia. Several wellspacing scenarios were modeled for each reservoir-permeability case to determine the optimum one. Simulation results show that closer well spacing or a higher number of wells generally leads to higher production rates, especially at early times, and ultimately to higher total gas production over the course of 20 years of production time. As well spacing becomes smaller, the drainage area for each well becomes smaller and the transient period is shorter. If the boundary is reached before the end of the 20-year production period, well interference occurs.
The relationship between reservoir permeability and well spacing states that the lower the reservoir permeability, the closer the well spacing, in order to drain the reservoir over a specified period of production time
Well Spacing vs. Number of Fractures.
The number of transverse fractures induced in horizontal wells is one of the important factors influencing optimum well spacing in tight gas reservoirs. To find the optimum spacing, two reservoir-permeability scenarios were considered: 0.01 and 0.1 mD.
To avoid flow interference, in 0.01 mD reservoirs, horizontal wells intersecting three transverse fractures need to be 500 m apart, while wells intersecting 12 fractures need to be approximately 700 m apart. As the number of transverse fractures increases, the contact area with the reservoir also increases. That leads to higher production rates, especially at an early time, and faster reservoir depletion. As a result, with more fractures intersecting horizontal wells, fewer wells are needed to drain the reservoir and more distance is needed between the wells.
Well Spacing vs. Fracture Half-Length.
Fracture half-length is another controlling parameter in the well-spacing-optimization study. The well spacing between multistage-fractured horizontal wells is optimized over 20 years of production. Gas production from horizontal wells was modeled in 0.01 and 0.1 mD reservoirs. Because production from 1.0 mD reservoirs is insensitive to fracture properties, higher-permeability reservoirs are not considered here. In addition, fracture spacing of 100, 200, and 300 ft was considered for scenarios of 3, 6, and 12 independent fractures.
As the fracture half-length increases, the horizontal well’s contact area with the reservoir also increases, resulting in higher production rates, increased drainage areas, and larger well spacing. Two interesting conclusions may be drawn here. First, horizontal wells with a reduced number of fractures with shorter half-lengths require reduced well spacing, whereas, with a higher number of longer fractures, a larger spacing between wells is required. Second, the product of fracture half-length and number of fractures is what influences the reservoir contact area, hence the optimum well spacing. This conclusion applies only under the assumption of a homogeneous formation, where fractures have equal contribution to flow.
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