SIMULATION SHOWS EFFECTIVENESS OF DOWNHOLE CHOKES IN HORIZONTAL WELLS

Roger Tallby
Den norske stats oljeselskap AS
Stavanger, Norway

Jostein Alvestad, Adolfo Henriquez
Den norske stats oljeselskap AS
Trondheim, Norway

Simulation demonstrates that a much better performance can be expected from a horizontal drain if different zones are isolated and inflow from each zone is controlled by downhole chokes.

This technology is well suited for thin oil zones, reservoirs with dipping layers with different permeabilities, and completions where damage governs inflow characteristics.

Horizontal wells have been proven to increase productivity and recovery in many reservoirs. The increase is achieved by different mechanisms in different situations. Reducing conings, increasing sweep efficiency, draining of vertical fractures, and accessing several geological structures are some of the areas where horizontal wells have been used.

This technology still needs optimized completion techniques that could further augment its economic potential such as exploiting previously marginal reservoirs.

It is difficult to predict at which point in the horizontal trajectory unwanted fluid may enter the well.1 2 Because reservoir heterogeneities such as local barriers to flow or high permeability streaks are not known beforehand, the final completion has to be chosen after production reveals problem zones.

The case of the Rospo Mare field, operated by Elf Aquitaine, and the well Lacq 91 are examples where the borehole is not cased until the behavior of the field is known.1

The remedy advocated, and not existing at the time, was to divide the well into different sections which could then be opened or closed selectively. Flexible and cost-effective control of the inflow performance of horizontal wells can be obtained by the use of multiple completions inside prepacked screens or perforated liners.

HORIZONTAL WELL USE

Horizontal wells have been used to solve specific problems, but optimizing completion had been deferred until the horizontal drilling technique was mastered.

In general, heterogeneities may reduce the recovery of a horizontal well by nonuniform oil production. This nonuniform oil flow may be due to heterogeneities in the reservoir (permeability contrasts, tight shale or carbonate cemented layers, or concretions), the geometry of injection-production wells (gravity override, and gravity segregation), vicinity to lateral boundaries, or uneven front movements.

It should be noted that longer wells have more probability of encountering reservoir heterogeneities, and therefore more need for flexible completion strategies.

In the Zuidwall gas field 3 a staircase" well bore trajectory was chosen because the thin productive layers (6 and 12 respectively) were separated vertically by low permeability layers.

In this case, the possibility of regulating the inflow from these layers by a flexible completion would allow a balanced pressure drawdown to avoid potential crossflow between the layers. This applies also when different oil-leg thicknesses, due to capillary pressure barriers or sealing faults, may be penetrated by one horizontal well.

Horizontal wells drilled in reservoirs with steep dip may penetrate layers with highly contrasting permeabilities (as in the case of the Etive and Rannoch formations in the North Sea). A flexible completion would allow control of the production rate and sweep efficiency in an optimal manner.

In the case of conducting faults which may lead unwanted fluid to the well bore, closing the offending interval will increase the effective life of the well.

A special case, which has arisen in practice, where a flexible completion technique would be helpful is in the drainage of a wedge region. The conservative approach would be to perforate a zone and then observe the development of the water-cut and the gas-oil ratio.

When the oil rate falls under the economic limit, the open zone is plugged and another is perforated. This approach is expensive offshore because of high rig rates and long periods of lost production.

WELL SERVICING

Zone isolation and other well servicing tasks are not easily accomplished in horizontal wells. Because of the unavailability of the most common well maintenance technique, wire line, successfully performing minor well intervention is a potentially expensive problem.

Coiled tubing has been resorted to when high deviation is a problem. The coiled tubing functions as stiff wire line in horizontal wells of short-to-moderate length in addition to its original function of conveying fluids.

An electric cable can be inserted in the coiled tubing for operations such as perforating and production logging, but mechanical tasks are severely restricted, even more so as the length of the horizontal section increases.

When the horizontal section exceeds about 600 m, the buildup of frictional forces begins to be significant, and when helical buckling occurs, the increased friction can quickly lead to lockup. This effect is exacerbated in large diameter liners, with the possible result that the lower part of such wells may not be accessible at all for the commonly available coiled tubing sizes and materials.

Even when access with coiled tubing is possible, tasks other than logging, perforating, or fluid circulation are not regarded as state-of-the-art. Because buckling due to friction alone is often sufficient to cause a problem, it follows that compression transmitted with coiled tubing through long horizontal sections is not automatically feasible.

Although coiled tubing is capable of transmitting hydraulic power, tools to utilize this are not presently on the market.

Full utilization of the potential of horizontal wells can often depend on the ability to produce or isolate different perforated zones. An additional advantage would be realized if production from these zones could be regulated on an individual basis.

This requires a completion strategy based on dividing the available reservoir sections into individual zones with production packers set on a continuation of the production tubing. Access is controlled by sliding sleeves.

A new technique has been developed that makes maintenance of this kind of completion possible. It involves a mixture of coiled tubing and through-flowline (TFL) techniques suitable for large diameter, platform-based producing wells.

With the help of this concept, called coiled-tubing-assisted pumpdown (CTP), individual zones may be opened, closed, choked, tested, or stimulated. Prototype equipment has been tested, and the technique has been shown to be feasible.

CTP

The CTP concept requires that a ported nipple be installed at the bottom of the tubing, immediately above the production packer at a point where the well would normally have a deviation approaching 90. This port is closed during normal production by a circulation control valve, which is opened permanently by applying differential pressure. The valve is pulled by conventional TFL methods before commencing CTP.

Zone isolation in the horizontal part of the well is achieved by extending the tubing string through a series of production packers separating the various perforated intervals. Installed in the tubing between the packers are sliding sleeves which may be opened to provide fluid access to or from the perforations (Fig. 1).

TFL-related operation of these sliding sleeves requires that standing valves be installed inside the sleeves when the sleeves are opened. This prevents the TFL operating pressure from leading to a loss of fluid to the formation.

These valves open under differential pressure from the formation and allow production through the open sleeves. The sleeves are closed by retrieving the standing valves.

In addition, these concentric standing valves (CSVs) are open through their centers, thereby allowing simultaneous production from lower zones. Installation of up to ten of these valves is standard TFL technology.

Standard TFL technology, however, does not allow well servicing at large distances below the circulation point. The fact that the well is horizontal is of no consequence. It is the use of coiled tubing in the TFL tool string that allows an apparently unlimited reach below the ported nipple and the production packer.

CHOKING INDIVIDUAL ZONES

Once valves can be installed to control access to individual zones. The values can also be given a reduced radial flow area. The valves then function as chokes for the zones they control. This is especially useful for wells with heterogeneities in the form of formation dip, faults, or permeability variations, all of which could lead to premature water or gas breakthrough.

Even in homogeneous formations, high productivity wells can suffer inflow variations because of pressure drop along the liner length.3

Fig. 2a shows a hypothetical series of choke responses that might be desirable for a given well or field.

Fig. 2b shows the results of prototype tests of two of these chokes (C and D) incorporated into a CSV.

Even if it is difficult to pick the choke size required in advance, the possibility for individual zone testing inherent in the CTP concept allows a trial-and-error approach is necessary. Because the CSV is a retrievable valve, changes of reservoir performance over a period of months or years can be accommodated.

In addition, equipment has been designed to enable treatment of individual zones. This involves an injection valve allowing fluid access to the formation from the tubing.

RESERVOIR SIMULATION

A few examples will illustrate the improvement that may be achieved on production performance and recovery efficiency by using an optimal completion strategy. All examples are black-oil problems with undersaturated oil systems. The pressure-volume-temperature (PVT) data and the relative permeability data for Examples 1 and 2 are found in Reference 5.

EXAMPLE 1

Example 1 models a reservoir with a thin oil zone. The reservoir model is quadratic in shape (3 km x 3 km) areally and 300 m thick. The top of the reservoir is horizontal and the oil zone is 30-m thick underlain by a large water zone.

The oil is produced by a horizontal well located in the middle of the reservoir with direction parallel to the reservoir edge and extending 500 m in each direction from the areal midpoint of the reservoir. Vertically the well is located approximately 3 m below the top of the reservoir.

The reservoir model is homogeneous and anisotropic with porosity f = 0.3, horizontal permeability kh = 2(mM)2 and vertical permeability kv = 0.1 kh. The production rate is 5,000 cu m/day at reservoir conditions. Two completion strategies are studied:

Complete and evenly perforate the whole well length with inner well diameter of 0.134 m (5.3 in.).
Complete the well with 10 separate zones each 100 m long and evenly perforated. The inner well diameter is 0.134 m and the inner diameter of the central tubing is 0.079 m (3.1 in.). Chokes are inserted at the end of each completed zone, with choke settings such that water breakthrough occurs approximately simultaneously along the well. After breakthrough, the choke settings are adjusted to minimize the water cut.

The results for these two strategies show both a significant delay of the cone breakthrough time (almost a doubling) and a reduction of the water cut at later times (Fig. 3a) for Strategy 2 due to an improved inflow profile. The gain in oil recovery after 6 years production is approximately 3% of the total production at that time.

The inflow rate distributions for Strategies 1 and 2 (Fig. 3b) show the more even profile of Strategy 2 initially and the enhanced production from the well ends later to minimize the water cut.

The results for these two strategies show both a significant delay of the cone breakthrough time (almost a doubling) and a reduction of the water cut at later times (Fig. 3a) for Strategy 3 due to an improved inflow profile. The gain in oil recovery after 6 years production is approximately 3% of the total production at that time.

The inflow rate distributions for Strategies 1 and 2 (Fig. 3b) show the more even profile of Strategy 2 initially and the enhanced production from the well ends later to minimize the water cut.

EXAMPLE 2

This example is a reservoir model with a dip of approximately 6.8 and which is eroded at the top. The height of the oil column is 60 m. The reservoir extends 2 km laterally in the dip direction and the width in the dip normal direction is set to 1 km.

Vertically the reservoir is subdivided into three different and isolated geological layers each with distinct geological and petrophysical properties (Fig. 4).

The reservoir is produced using a horizontal well located in the middle of the reservoir laterally and approximately 3 m below the top of the reservoir. The well lies in the dip direction and enters from the top of the formation.

Pressure maintenance and water drive are provided by two vertical wells located at the reservoir boundaries (Fig. 4b).

This corresponds to a symmetry element of a staggered line drive situation in the dip normal areal direction.

The production rate is 5,000 cu m/day at reservoir conditions and it is kept constant for 10 years. The injection wells are completed and evenly perforated in all three geological layers and replace the total voidage of the production.

Here are four strategies for completion and operation of the production well:

Complete the whole well length, perforate evenly with inner well diameter of 0.134 M.
Complete the well as under Strategy 1, but close approximately every 100 m interval when the water cut of the interval exceeds 0.9.
Complete the well by four separate zones, one for each of the two upper geological layers, and two for the lowest geological layer (approximately equal length). Chokes are inserted to control the flow from the three zones towards the outflow end of the well such that the water breakthrough time in each of the four completed zones is nearly the same.
Complete one geological layer at a time, starting with the lowest layer. Produce until a water cut of 0.9 is reached, then close the zone and complete and produce the next zone.

The numerical results are obtained using gridblocks of (26 x 50, 2 x 100, 2 x 250) x (2x25, 3x50, 2x100, 112.5) x (16x6)(m)in the dip, dip-normal, and vertical directions, respectively. Only half of the symmetry element in Fig. 4a is simulated, using the additional symmetry around the vertical cross section through the well axis.

The results from the different cases show clearly that Strategy 3 is the most favorable (Fig. 5).

Isolation of watered-out zones is beneficial, leading to reduced water production and accelerated oil recovery. Simultaneous production of the whole well is beneficial compared to a staged production of the different geological layers.

The period of water free production is largest for Strategy 3 (Fig. 5b). Another important factor is the total water production at a given oil recovery which also differs significantly (Fig. 5c). This indicates that an unfavorable completion strategy may lead to the requirement of handling substantially more water than in a more optimal case.

The initial inflow performances for Strategies 1 and 3 (Fig. 5d) show that a more even inflow profile is preferable. The actual choke parameters (referring to the chokes of Fig. 2a) and the time dependence of these (Table 1) show that only minor changes are needed to keep the calculated inflow profile of Strategy 4.

The plus signs indicate that the actual choke property needed is midway between the specified choke and the next choke with larger pressure drop.

For practical purposes, the same choke settings may be used over the whole production period or until a particular zone is closed.

An estimate of the sensitivity of the inflow profile to changes in the total well flow rate and the producing water cut has been calculated using a simplified stationary model. A change of less than 6% in the relative contribution from each of the four intervals to the total well flow rate results from varying the total reservoir flow rate from 2,000 to 8,000 cu m/day and varying the water cut between 0 and 1 for a reservoir flow rate of 5,000 cu m/day.

The weak rate dependence of the inflow profile can be explained by the approximate quadratic rate dependence of both the pressure drop through chokes and the pressure drop in the tubing, that is for the actual volumetric rates where turbulent flow dominates flow.

The water cut dependence is mainly due to the difference in fluid density between oil and water.

EXAMPLE 3

Example 3 comes from an evaluation study on the production of the oil reserves in a fault block in a North Sea field. The oil reserves are located in the lower Brent formation with an estimate of some 4.7 million cu m (30 million bbl) initial oil-in-place and are distributed in the form of a wedge zone of varying thickness in the north-south direction (Fig. 6).

Most of the reserves are located in a central region which is structurally highest. Vertically, the reservoir is divided into these zones (layers) separated by flow barriers of large areal extent which limits the vertical flow significantly between the three different layers.

The average petrophysical properties in each layer are similar to the properties of the three layers in Example 2.

Numerical simulations have shown that the oil reserves in the fault block are efficiently,produced using a 8,000 m long well drilled in the south-north direction (Fig. 7) structurally high and close to the fault on the east side of the fault block.

The well enters the reservoir as a highly deviated well penetrating the three main layers (necessary to recover the oil in each of the layers) and is then gradually made horizontal as shown in Fig. 7.

Because of the distribution of the oil reserves and the contrasts in the petrophysical properties between the three layers, an optimal inflow profile for the well is not automatically obtained. Furthermore, zone isolation is needed to reduce the water production after water breakthrough.

The initial oil rate is 2,000 cu m/day and the maximum allowed water production rate is 1,000 cu m/day. Pressure maintenance is provided by an injection well in the water zone replacing the production voidage.

Here three different completion strategies for the production well are compared:

Complete and evenly perforate the whole well, inner well diameter equal to 0.14 m (5 1/2 in.).
Complete the well with 10 separate zones of varying length (adjusted to the layering). Chokes are inserted to optimize the inflow profile with respect to water breakthrough.
Complete the well the same as Strategy 2, plus isolate completed zones exceeding a water cut of 0.9.

The results show that Strategies 2 and 3 give a delay of the water breakthrough time from 140 to 360 days. Strategies 2 and 3 give, respectively, 6% and 8% higher total oil production compared to Strategy 1 after 4 years. This recovery corresponds to approximately 33% recovery of the in-place reserves.

Turning to the total amount of water produced at a recovery of 38%, Strategies 2 and 1 give, respectively, 18% and 51% more water production than Strategy 3 which has a total water production of 2.0 million cu m at this oil recovery.

This means that Strategies 2 and 3 significantly reduce the amount of water that needs to be treated compared to Strategy 1.

BENEFITS OF CHOKES

The examples have illustrated that choking of individually completed zones can be beneficial by delaying water breakthrough and reducing water production for a given oil recovery. In addition, zone isolation is necessary in most cases to reduce water production.

A necessary condition for choke control to be effective is that the whole completed length have sufficient pressure support.

This means that if one part of the completed reservoir section has pressure support while another part is subject to pressure depletion, then choking individual zones cannot be used to simultaneously produce the reservoir section without pressure support.

In some situations, highly permeable regions along the well trajectory will reduce the effect of isolating a zone if fluid from that zone can easily move to neighboring zones which are open.

Because of the two parallel flow areas in a multiple completion, the frictional pressure drop will be larger than for a conventional completion. Therefore, the length of each isolated zone should not be too long. A shorter length avoids a biased inflow profile in each zone.

Intervals of 200-300 m are feasible even for reservoirs with permeabilities of several Darcies.

The concept of individual zone control should apply equally well to problems involving gas displacement or gas coning, under most circumstances. The quantitative improvement must, however, be determined in each case.

The results so far indicate that the more heterogeneous the reservoir, the larger the improvement.

In many cases, for example in a gas coning situation, reopening of a previously closed zone may be attractive. The CTP concept provides a cost-effective means of achieving this, since rig costs and lost production are minimal.

An important feature of the CTP concept, including the capability of choking individual zones, is that inflow control may be introduced or modified as a result of well tests of each zone after production has stabilized. In addition, crossflow or interflow is not possible in a CTP completion.

ACKNOWLEDGMENT

The authors would like to express their appreciation to Statoil for the permission to publish this article.

The collaboration of Martin Madsen in the simulation of some examples mentioned in this article is acknowledged.

REFERENCES

Spreux, A., and Georges, C., OGJ June 13, 1988.
Reiss, L.H., "Production from Horizontal Wells After 5 Years," JPT, November 1987, pp. 1411-1416.
Dikken, B.J., "Pressure Drop in Horizontal Wells and its Effect on Production Performance," JPT, November 1990.
Legris, B., and Nazzal, G., "Specifics of Horizontal Drilling in the Zuidwal Gas Field," SPE paper No. 19251, Offshore Europe 89, Aberdeen, Sept. 5-8, 1989.
Silseth J.K., MacDonald, A., Alvestad, J., Buller A.T., and Torp S.B., "Impact of Flow Unit Reservoir Description on Simulated Waterflood Performance: A Sensitivity Study Based on a Synthetic 3D Geological Model," SPE paper No. 20603, 65th Annual Technical Conference and Exhibition of SPE, New Orleans Sept. 23-26, 1990.