A pioneering horizontal drilling program in a depleted North African reservoir is using underbalanced drilling (UBD) methods to increase production, improve drilling penetration rates, reduce rig time, and provide reservoir evaluation while drilling. The first three wells of the program have been successfully drilled and completed with outstanding results that are bringing a new vitality to the aging asset.

Cost reduction efforts in the program include mitigation of lost circulation and differential sticking as well as reducing stimulation and cleanup costs. Productivity improvements are focused on increasing ultimate recovery and real-time reservoir characterization while drilling.

Enhancing a mature reservoir

Concentric gas injection enables conventional mud pulse telemetry and faster connections. (Images courtesy of Weatherford)

The pilot project involves drilling six underbalanced horizontal wells to reach an early Cretaceous sandstone reservoir. Production from the mature field began in the late 1960s and has been dependent on electrical submersible pumps for nearly 20 years. The partly depleted oil structure has declined from an initial pressure of nearly 3,990 psi to about 2,400 psi.

Improved drilling and production rates were established with the first two wells. The third well focused on minimizing formation damage and maximizing production. In addition, it provided an opportunity to evaluate production while drilling as a means to eliminate expensive post-drilling production testing. No lost time or QHSE incidents were experienced and operations were accomplished according to plan. (These efforts are detailed in SPE 128440.)

Depending on reservoir pressure and depth, UBD conditions are achieved in two ways — by using noncompressive drilling fluids or by adding gas to reduce drilling fluid density. Underbalanced conditions, achieved when the equivalent circulating density of the drilling fluid is less than reservoir pressure, allow reservoir fluids to continuously flow into the well bore.

The equipment used to achieve UBD conditions are carefully considered according to well conditions and objectives. Circulating system design must enable control of bottomhole circulating pressure so a continuous, steady state of underbalanced conditions can be maintained. Hole cleaning must be assured at any depth or inclination. Motor and bit operational specifications must consider single-phase or equivalent two-phase compressed fluid volume throughout. And surface separation equipment capacities must be matched to the application design.

Multiphase (gas-liquid) drilling fluid systems are used to manage bottomhole pressure below the normal pressure regime. In this UBD program, native crude oil was chosen over diesel to minimize formation damage in the event of pressure transients or from fluid imbibitions. Nitrogen (generated onsite) was selected as the injection gas because of its inert nature, economic availability, and suitability for this specific UBD project.

Gas injection methods

In the first well drilled, total crude production during UBD operations amounted to 4,405 bbl.

The method of injecting gas is a key consideration. The most common form is drillpipe gas injection in which gas and liquid are mixed at surface and injected down the drillstring. The advantage of this methodology is that it requires the least number of modifications to the well design. It also tends to produce better control and lower bottomhole pressures.

The main drawback is that gas passing through the bottomhole assembly constrains downhole motor and measurement-while-drilling (MWD) operations. An electromagnetic MWD or wet-connect MWD generally is required.

The second method is concentric casing injection. In this approach, the liquid phase is injected down the drillstring at the surface (per conventional drilling operations) and the gas phase is injected via a concentric casing injection string behind the primary wellbore casing.

This method allows the use of conventional mud pulse MWD. Connections are also quicker with concentric casing injection systems because the drill string only contains a single-phase non-compressible fluid. The time needed to bleed off the string is reduced considerably.

The disadvantage is that due to the “accumulator effect,” the circulation system is rather unstable. An appropriate estimation of the flow area where the gas will be injected to the drilling annulus is required. The method also reduces the operational range of bottomhole circulating pressure (BHCP) for a specific well configuration. In addition, a tieback string is required along with modifications to the wellhead.

Modeling multiphase flow

This graph from Well # 3 illustrates the production curve against time and depth and a visual breakdown of different phases of the well’s progress. During the drilling time of the well, 2,430 bbl of crude were produced.

Rigorous multiphase flow simulation software is used to determine the response of the well to changes in downhole conditions. Circulating pressures and hole cleaning parameters were evaluated, and appropriate equipment and injection rate were selected.

This modeling was the basis for choosing the concentric casing gas injection method. Since no gas is flowing through the drillpipe, the liquid velocities in the horizontal section limit the operational window for the hydraulic injection parameters. Production-while-drilling was expected to enhance the transport of cuttings in the horizontal section, increasing the operational window.

For the first well, a 6 1/8-in. horizontal section was drilled from the 7-in. liner shoe at 9,183 ft (2,799 m) measured depth (MD) to 10,817 ft (3,297 m) MD. The BHCP was maintained between 2,149 psi and 2,327 psi. An increase in rate of penetration (ROP) was achieved with 1,634 ft (498 m) drilled in 44.27 hrs (bit on bottom) at an average ROP of 36.9 ft/hr (11.2 m/hr).

Oil production began immediately after unloading the well and about 10 ft (3 m) into the producing formation. At that point, diesel was replaced with produced oil. A total 1,634 ft of open hole was drilled at a controlled drawdown of 10% of the reservoir pressure, which was estimated at 2,400 psi.

A production test was performed at total depth (TD) for three hours with 1,750 cf/m nitrogen. Oil was produced at an average rate of 5,584 b/d, and reservoir gas was produced at an average rate of 390,000 cf/d. The average flowing wellhead pressure was 245 psi.

The second well involved a 6 1/8-in. horizontal section drilled underbalanced from 8 ft (2.4 m) outside the 7-in. liner shoe at 9,205 ft (2,806 m) MD to 10,889 ft (3,319 m) MD. The well began producing at 9,772 ft (2,978 m) MD, and diesel was replaced with produced crude. A total of 1,684 ft (513 m) of open hole was drilled at a controlled drawdown of 6 to 10% of the estimated 2,400 psi reservoir pressure.

An increase in ROP was achieved with 1,684 ft drilled in 85 hours for an average rate of 39 ft/hr (12 m/hr). The BHCP was maintained between 2,100 and 2,280 psi. Oil production while drilling was first observed at 9,772 (2,979 m) MD, and 2,360 bbl were produced during UBD, tripping, and circulation.

At 10,889 ft MD, a production test was performed for an hour with 2,500 cf/m nitrogen. Oil was produced at an average rate of 5,448 b/d along with 780,000 cf/d of gas. The average flowing wellhead pressure was 200 psi.

The third well was built on previous experience with the intent to minimize formation damage, which, in turn, maximizes well production. The well was drilled in a record time of 8 days from start of UBD to TD, yielding approximately three times the average conventional production in the field.

The average ROP during UBD was 21.2 ft/hr (6.46 m/hr). Good hole cleaning was achieved through the 6 1/8-in. UBD section by careful application of drilling rates and working the pipe after each connection.

A total 2,430 bbl of crude were produced while drilling. Immediately after production began, a preliminary flow test recorded production of 2,662 b/d of oil and 0.6 mmscfd. UBD continued to TD. A final flow test yielded an average production of 3,650 b/d and 172,000 cf/d of gas.