Flow Control in Horizontal Wells
1. Understanding Mechanics and Hydrodynamics in Horizontal Wells
Flows in horizontal wells exhibit pipeline flow not vertical well flow characteristics. Flow in horizontal wells, as with pipeline flow, is dominated by friction effects as opposed to hydrostatic head effects found in vertical wells.
The length of the lateral, and the way production contribution or injection distributes along that length can cause widely varying flow velocities across the lateral. Changing velocities impact the ability of the flow in the well to transport fluids, and mobilize any solids, sand, or mud that have entered the wellbore.
Multiple hydraulic flow regimes can exist along the length of the lateral, ranging from laminar flow in the low velocity areas toward to the toe to slugging or turbulent flow as flow velocities increase towards the heel of the well. Variations in velocity, friction factors, flow regimes, and transport capabilities along the lateral may contribute to production problems. Large pressure drops, unstable flow, inability to remove solids from the entire length of the wellbore or inability to clean up the wellbore upon initial production combine to impede productivity.
For injection wells, the same issues hold true whether liquids or gases are injected. The magnitude of the effects will change depending on the type of injection. Friction effects are lower withgases, but. small variations in pressure can also have dramatic effects, for example steam quality.
2. Understanding Hydrodynamics and Reservoir Heterogeneity
Long laterals are likely to intersect reservoir rock with widely varying productivity or injectivity capabilities. Industry experience with horizontal wells has taught us that reservoirs are more heterogeneous than we thought. This variability has a big impact on our ability to design effective flow control in the wellbore. The combination of changing permeability and a varying pressure profile leads to wide differences in production and injection capability along the lateral. The engineer cannot expect to maximize injectivity or productivity in the well unless he/she does something to actively manage these behaviors.
3. Don’t Stub Your Toe
The toe of the well is often the first place problems in injection or production may show up. The toe is arguably the most costly section to drill, and all too frequently does not contribute to either productivity or injectivity. Drilling an extended lateral length generally assumes two benefits: The first is maximizing productivity in the individual wells: and the second is optimizing sweep efficiency of the reservoir and maximizing ultimate reserve recovery utilizing fewer wells. Spending less capital increases the ultimate value of the resource. However, if the long sections you spend good money to drill are not capable of production or injection these goals are not met. Engineers can’t achieve optimum reserve recovery and efficient well productivity or injectivity along the entire well without taking active steps to manage it.
4. Plan for Wellbore Clean-up
An important step to optimizing horizontal well productivity is cleaning up the wellbore during completion. The same problems that make producing and injecting into the toe of the well difficult are present when the well is initially completed. Drilling the well leaves filter cake which needs to be removed to allow optimized productivity into the wellbore. A common strategy is to rely on the differential pressure of initial production to clean up the well. Chemical breakers may be pumped, but the strategy relies on having sufficient velocity when circulating the treatment fluid, and sufficient pressure differential when the well is brought on to remove the filter cake as well as any stimulation or completion fluids. Managing the pressure profile along the entire length of the lateral is essential to the success of the clean up strategy.
Engineers need to anticipate and plan to mitigate any clean-up problems at the onset early in the well design process. Damage is very difficult to correct if the well does not clean up in a uniform way on initial production, and remedial action is very difficult. Remedial stimulation tends to go to areas that are already productive. Therefore, mechanisms to allow stimulation and clean-up must be designed into the primary completion so that when the well is brought on, uniform clean-up is accomplished.
In summary, if engineers don’t employ an active strategy for controlling the pressure profile of the well and managing the interaction of the well with the reservoir, we cannot maximize productivity of the well. The factors discussed put a premium on the design of effective inflow, injection control, and sand control. Lack pf proper planning in the initial completion design will destroy well value.
- Understand the mechanics/hydrodynamics of your horizontal wells
- Understand the combined impacts of wellbore hydrodynamics and reservoir variability
- Plan for active management of how the wellbore impacts the reservoir.
- Plan for uniform wellbore clean up when the well is put on production
- Design effective injection, inflow and sand control as part of the initial completion design
Drilling horizontal wells creates the potential for very complex interaction between the hydrodynamics of the wellbore and the heterogeneity of the reservoir. These challenges can be overcome. Getting flow control right dramatically increases the size of the prize.