A variety of myths are being dispelled with inflow control technology, which passively controls the inflow profile along the lateral length of a well to allow the well bore to produce larger volumes while eliminating the onset of early water production and premature gas breakthrough. Inflow control technology has delivered sand control completions in lateral lengths exceeding 11,000 ft (3,355 m), eliminated water breakthrough in naturally fractured carbonate reservoirs and provided sand management without gravel packing in formations that otherwise would have required gravel media.

Inflow control technology basics

Horizontal wells can increase reservoir productivity, but they also pose unique reservoir
Figure 1. Inflow control device integrated with premium screen. (Images courtesy of Baker Oil Tools)  
drainage and sand management challenges. Long horizontal wells have inherently unbalanced inflow profiles. Without proactively managed inflow, frictional pressure drop causes the flow to be unevenly distributed and greatest at the heel of the horizontal section. As a result, water and gas move quickly toward the heel, and the well waters out prematurely, leaving oil behind. Similarly, uneven drawdown dislodges sand grains, which follow the path of least resistance to create localized problems which can disable the well or require costly intervention.

Inflow control completion systems such as Baker Oil Tools’ EQUALIZER systems were developed to create a uniform production profile along the entire horizontal section of a well and virtually eliminate annular flow. The uniform profile greatly reduces the risk of hot spotting, the primary cause of plugging and erosion in sand control screens. Controlling annular flow also prevents sand that becomes dislodged from the formation from being transported and redistributed down the annulus. As a result, the requirement for gravel packing is reduced, and screen life is extended. The uniform inflow profile also pulls water and gas evenly toward the well to maximize reservoir recovery by increasing well length and alleviating gas and water coning risks. Because of their ability to evenly distribute flow, inflow control completion systems are effective for both heterogeneous and homogeneous formations.

Sand exclusion for the Baker inflow control completion systems is achieved with a premium sand control screen. Uniform inflow is achieved with helical inflow control devices (ICD) mounted to the base pipe at the end of each screen, which allow flow to enter each screen at an equal rate along the entire horizontal section. The ICD is highly reliable and resistant to erosion. Size, length and the number of channels can be varied to control local production rate at any point along the well bore and allow for radial flow resistance from the annulus to the base pipe.

The 1,500-ft (457.5 m) limit

In a high-permeability formation completed with classical techniques such as standalone screens, gravel packing or expandable screens, the 1,500-ft limit sometimes applies, because flow resistance of the base pipe is greater than the flow resistance in the formation, causing increased inflow near the heel. In a low-permeability formation, the 1,500-ft limit does not apply at all, because the flow resistance of the formation overshadows the flow resistance of the base pipe, and non-uniform inflow does not occur.

Yet, the myth prevails, and the consequences of believing it can be costly.

To illustrate the impacts of the 1,500-ft-limit myth, a hypothetical reservoir with a bottom
  Figure 2. End of well life water-oil and gas-oil contacts for a horizontal well using EQUALIZERS.
water drive and dimensions of 8,000 ft (2,440 m) length, 1,400 ft (427 m) width and 50 ft (15.25 m) thickness was analyzed for three well completions: a 1,600-ft (488-m) well with standard screens, a 6,400-ft (1,952-m) well with standard screens and a 6,400-ft well with an inflow control completion system. For each well, the heel was located at 880 ft (268.4 m) length, 700 ft (213.5 m) width and 35 ft (10.7 m) height. All wells were horizontal and parallel to the water aquifer.

At the end of the productive life of the 1,600-ft well completed with standard screens, much oil remained beyond the toe. In the 6,400-ft well completed in the same manner, a large quantity of oil remained at the point where the well watered out.

Additionally, because heel of the well produced at a greater rate than the toe, the water-oil contact was higher at the heel. This phenomenon helps give rise to the 1,500-ft horizontal limit myth.

Completing the 6,400-ft well with an inflow control system equalized the inflow of oil along the horizontal length, which increased well length, access to oil, volumetric recovery and production rates. The oil production curves can be integrated to obtain volumetric recovery. Despite a high-permeability reservoir, the 6,400-ft well completed with standard screens had more than twice the recovery of the 1,600-ft well. The 6,400-ft well completed with inflow control tripled the recovery rate of the shorter well.

Near-wellbore flow rates for the 6,400-ft wells further illustrated the advantage of inflow control completions. With the standalone completion, flow rates were substantially higher near the heel and low from the toe of the well. The excessive velocity that results from this disparity in flow rates causes screen erosion and premature watering out of the well. The near-wellbore flow rates for the inflow control completion were nearly constant for the entire length of the well.

The 1,500-ft length limitation myth also comes about through misinterpretation of production logs. The common belief is that production logging tool (PLT) spinner logs indicate where the formation is producing. However, if an annulus exists between the screen and the sandface, flow in the annulus can cause misleading results. In reality, all a PLT spinner log will show is the magnitude of the flow rates in the base pipe. The actual reservoir flow rate is the production from the formation across the sand face.

Sand control without gravel packing
High velocity annular flow causes sandface erosion and dynamic sorting of sand in the annulus, often resulting in failure of standalone screen completions. Gravel packing typically provides sand control through annular flow reduction and filtration. These two conditions fuel the myth that wells must be gravel packed to achieve sand control and completion longevity.
Inflow control completions eliminate axial annular flow to enable sand control without gravel packing. The only caveat is that the premium screen must be able to retain the formation sand.

Critical coning
A common myth regarding vertical wells is that if the well is produced at a low rate, the aquifer will cone toward the well yet not reach the well.

Although this concept is valid where a gas cap pushes the oil down toward the well, it does not hold true for vertical or horizontal wells with bottom water drives. In the case of an aquifer drive, the water cone can never be stable because the water is continuously moving toward the well.

The myth of a critical rate or stable cone carries with it the assumption of an infinite reservoir. The assumption of an infinite reservoir also carries the assumption of an inexhaustible drive mechanism. For a vertical well in a large reservoir, this assumption can be considered valid for a finite period of time. For a horizontal well, the longer the lateral length, the more effect the well has on the reservoir and its associated drive mechanism. The faster and more completely the reservoir is depleted, the faster the underlying production assumption becomes invalid. The validity of the constant pressure assumptions can now be measured in days or even hours.

The realistic best-case scenario is to produce as much oil as possible before the well waters out. This goal is obtainable through inflow control technology.

Editor’s Note: Information in this article was taken from SPE 100316, presented at SPE Europec, Vienna, Austria, June 12-15, 2006.