MPD in Algeria overcomes previously undrillable fractured reservoir

Khelil Kartobi and Ibrahim Hamoudi, Sonatrach; Hani Qutob, Maurizio Arnone, Fabian Torres, Chad Murray and Naiem Barakat, Weatherford International Ltd.

Drilling with constant bottomhole pressure in Algeria’s Nezla Field has successfully penetrated formations where extremely tight pore pressure/fracture gradient windows have made conventional drilling impossible. The positive results achieved with Sonatrach’s first application of managed pressure drilling (MPD) in Algeria have laid the groundwork for expanding MPD-related development in the field as well as other assets in the country.

HIGHLY FRACTURED DRILLING

Nezla Field is located between Hassi Messaoud Field and Rhourd de Nouss Central Field in the Triassic Basin. Discovered in 1960, the geologically complex field includes the Quartzites de Hamra Formation, a highly fractured, gas-bearing sandstone reservoir.

The field has a daunting drilling history of total fluid losses leading to gas kick events. To manage these extreme pressure fluctuations, a constant-bottomhole-pressure (CBHP) MPD technique was selected to drill a 6-in. hole section through the field’s Gres de Ouargla and Quartzites de Hamra Formations.

Walking the line. As described by the International Association of Drilling Contractors, (IADC), MPD is an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The goals of MPD are to ascertain the limits of the downhole pressure environment and manage the annular hydraulic pressure profile accordingly. The intent is to avoid an influx of formation fluids or gas and, if there is an influx, to prevent it from reaching the surface by quickly managing pressure variations. It is this ability to dynamically control annular pressures that facilitates the drilling of what might otherwise be economically unattainable prospects.

Fig. 1. The narrow drilling window profile designed through the highly fractured Quartzites de Hamra sandstone was bounded by a lower limit of 1.30 sg equivalent mud weight and an upper limit of 1.36 sg EMW.

The CBHP technique used at Nezla Field is a variant of MPD used to mitigate a wide range of drilling hazards. It greatly reduces drilling nonproductive time (NPT) by managing the annular hydraulic pressure profile using backpressure control, fluid properties (such as density and rheology) and the circulating friction in the annulus. The CBHP technique has been used very successfully to “walk the line” between very narrow drilling limits.

Management and control. As a well pressure management tool, MPD supplements but does not replace traditional well control methods. The technology acts as a first line of response to prevent downhole pressure fluctuations from becoming well control events. If surface pressure exceeds MPD ratings, the rig mode transitions seamlessly to conventional BOP and mud weight control procedures.

The IADC well control matrix provides the MPD interface for establishing the appropriate response when conditions deviate from the original plan to an imminent hazard. Manageable wellhead pressures must be determined to ensure continuous and safe drilling operations. Well control events may occur when the return flow parameters reach established criteria or when an imminent hazard prevents the continuation of safe drilling operations. The well control matrix defines this well control interface between MPD operations and conventional well control.

A risk-based approach to the design of the flow control matrix is required. This is based on two key factors: the pressure rating of the flow control equipment (rotating control device, MPD choke manifold and primary flowline) and the MPD casing design limit (the maximum allowable annulus surface pressure as a function of the planned mud density).

MPD well candidates. Experience with MPD in the Middle East and North Africa, as well as extrapolated worldwide experience, shows that well candidates are typically identified by one or more specific drilling problems and/or planned objectives.

Perhaps the highest-profile capability is in drilling formations where conventional methods have failed. These “undrillable” formations typically exhibit tight pore pressure/fracture gradient windows; are vuggy, fractured carbonates that make circulation impossible; or have high in situ stresses that make reaching target depth problematic. In these difficult circumstances, MPD often improves performance such that casing can be set deeper, reducing related costs and enabling the production zone to be drilled with a larger borehole.

In addition to the conventionally undrillable, MPD candidates also include many drillable wells where the objective is to enhance safety and efficiency, and ultimately reduce costs. These uses involve such diverse applications as extending the reach of extended-reach wellbores, increasing the rate of penetration (ROP) by drilling closer to balanced conditions, and reducing loss/kick occurrences and the time spent dealing with pressure-related events.

MPD methods are also selected to help drillers differentiate between ballooning effects and a kick, and to reduce pressure cycles that cause fatigue-related borehole instability. Limiting openhole exposure time further reduces instability. Because losses are reduced and pressure is managed without weighting up, mud costs are also minimized by an MPD program.

MPD well candidates are also defined by safety and environmental concerns. In these applications, MPD enhances trip safety by managing pressure fluctuations while tripping to reduce swabbing and surging. Because the annulus is closed at the surface and flow is directed away from the rig floor, sulfuric acid and high-pressure/high-temperature hazards are greatly mitigated. In marine and other environmentally sensitive areas, operations are enhanced by positive fluid containment at the surface.

Algeria MPD objectives. The overall objectives in using MPD at Nezla Field were to enable the well to be drilled and, in doing so, to devise a strategy to safely develop the field. The well was a good MPD candidate because of its extremely tight drilling window. MPD presented a significant advantage—in terms of time, cost and effectiveness—in its ability to adjust equivalent circulating density (ECD) by changing downhole pressure at the surface almost immediately, compared with changing the mud weight. With the MPD system, kicks were easier to identify and correct, and steady bottomhole pressure could be maintained while circulating or with the pumps off.

A very detailed project management program was put in place, beginning with the analysis of trouble time associated with nearby wells.

The offset evaluation showed that NPT was associated with several conventional drilling practices in the field. Time was lost making changes in static fluid density to control gas influxes and circulation losses. Another NPT source was pumping lost circulation materials and cement plugs to cure losses. Stuck pipe, differential sticking and twist-off-related fishing operations also contributed to NPT, along with late identification of well control events, including one that ended in a blowout. Low ROP contributed to overall poor efficiency.

Both offset wells were under constant risk of loss/kick cycles. A quick response was required to control the fluctuations, but conventional practices required a lengthy process of adjusting mud density in the wellbore. As a result, both offset wells failed to reach target depth. More than 50% of total well cost and drilling time was associated with NPT. In one well, a catastrophic blowout occurred when the difference between pore pressure and fracture gradient exceeded the operational capabilities of conventional drilling techniques.

NEZLA FIELD DRILLING PLAN

To overcome these challenges, the CBHP method was selected to drill the 6-in. section through the Gres de Ouargla and Quartzites de Hamra Formations. The operational objectives were to evaluate and ascertain the upper and lower limits of the drilling window and to maintain constant bottomhole pressure during dynamic (circulating—pumps on) and static (pumps off) conditions.

The well plan involved hanging a 7-in. liner from 9⅝-in. casing and setting it in the Gres de Ouargla at about 2,400 m (7,900 ft). A 5⅞-in. hole would then be drilled about 300 m (1,000 ft) into the Quartzites de Hamra to about 2,700 m (9,000 ft) TD.

The drilling window was determined by estimating a formation pressure of 1.30 specific gravity equivalent mud weight as the lower limit (pore pressure), and 1.36 sg EMW for the upper limit (fracture gradient), Fig. 1. Both values were calculated at the top of Hamra Formation. The lower limit estimation was based on the analysis of drilling problems experienced in offset wells. In those wells, total fluid losses were reported while drilling the Hamra interval at about 2,100–2,400 m (6,900–7,900 ft) using drilling fluids with a density ranging 1.36–1.40 sg. These values were used to establish the ECD for drilling the hole.

Thermal considerations. A 1.14-sg diesel oil-based mud was selected pursuant to company policy of drilling the pay zone with a formation-friendly drilling fluid. While a normal downhole temperature gradient was anticipated, variations in the profile were important to the hydraulics modeling done to define the pressure profile within the operational drilling window.

The thermal effect along the wellbore produces changes in the rheological properties as well as the density of the drilling fluid. These changes alter the downhole pressure profile even during static conditions due to thermal expansion and density reduction.

Simulator assumptions. The ECD management plan required that numerous assumptions be made in order to run the hydraulics simulator. These ECD calculations assumed an oil-based mud with a weight of 1.14 sg, a plastic viscosity of 20–25 cP and a yield point of 0.15–0.20 lb/ft2. Pore pressure was estimated at 1.30 sg EMW. Temperatures ranged from a static bottomhole temperature of 101°C (214°F) to 37°C (99°F) surface temperature.

The mud pump rate was set between 700 and 800 L/min. (4.4–5.0 bbl/min.) to ensure hole cleaning and the functionality of downhole tools. Other modeling assumptions included a wellhead pressure of 300–400 psi while circulating at 2,763 m (9,065 ft), a cutting density of 2.25 g/cm3 with 0.05-in. diameter, and a penetration rate of 2–3 m/hr (6.6–9.8 ft/hr). ROP was controlled to minimize the amount of cuttings present in the wellbore, because high cuttings volumes could increase the ECD.

The simulated ECD management plan considered the bit depth as the pressure balance point for maintaining constant bottomhole pressure during static and dynamic conditions. To maintain this condition during pumps-off periods, such as when making pipe connections, mud would be pumped across the top of the annulus so backpressure could be applied with the MPD choke.

The required wellhead pressure or equivalent MPD choke pressure values were calculated as a function of pit gain. These values determine how much backpressure should be applied on the MPD choke to regain balanced bottomhole pressure conditions. The volume of drilling fluid replaced by the formation influx represents a loss in hydrostatic pressure in the annulus.

Testing the assumptions. Because drilling window limits for the CBHP technique were based on estimations, a window ascertainment test was planned. The test validates the limits by determining the bottomhole pressure where an influx from the formation and fluid losses occurred.

The window ascertainment test was run by performing formation integrity and inflow tests. The obtained values suggested a different window than the one planned, with 1.27 sg EMW for lower limit (previously estimated at 1.30 sg) and 1.40 sg EMW for the upper limit (estimated at 1.36 sg). These values were later used to establish the target ECD for drilling operations.

DOWNHOLE ISOLATION VALVE

A downhole isolation valve (DIV) was run with the 7-in. liner string and set at 1,350 m (4,430 ft), Fig. 2. There were two key goals in using the DIV. First, with the valve in place, the need to kill the well prior to tripping pipe out is eliminated. This was a critical well control concern in the gas producing formation, where fluid losses could occur while killing the well. Potential damage to the producing formation was also a concern.

In addition, the risks of swabbing gas from the formation while tripping out of the hole and of surging while tripping in were concerns, particularly in the 6-in. section where the drilling window was very narrow. Closing the DIV reduces these effects.

The surface-controllable, flapper-type valve is an integral part of the well’s casing/tieback liner string. When a trip is necessary, the drillstring is stripped out through the sealing elements of the rotating control device (RCD) until the bit is above the DIV. The valve is then closed from the surface, pressure above the valve is bled off, and the drillstring is retrieved without the risk of swabbing in the well below the valve. Pipe is tripped back into the well with the valve protecting the hole beneath it from surging effects. The valve is opened when the bit reaches it, and the pipe is tripped to bottom.

The DIV is opened and closed from the surface through a control line run in the casing string annulus. The control line consists of two continuous lengths of ¼-in. tubing on either side of a 5/16-in. braided wire rope. The wire rope contains a monoconductor line to transmit operational data from the valve. The valve opens and closes when pressure is applied to the appropriate control line.

PRESSURE MANAGEMENT

The ECD was managed by controlling the surface backpressure with an MPD choke manifold using annular return flow on a coriolis-type flowmeter, and by real-time monitoring of changes in bottomhole circulating pressure using a pressure-while-drilling tool located in the bottomhole assembly.

The MPD system was configured for two circulation paths. One was used for circulation while drilling. It routed returning annular fluids from the RCD through the flowline to the MPD manifold and coriolis flowmeter, shale shakers, rig tanks, rig pumps and back down the drillstring.

The second circulation option was used when pumps were off while making drill pipe connections. This system circulated fluids through the kill line to the annulus and then through the RCD, the flow line, the MPD manifold, the coriolis flowmeter, the trip tank, the pre-charge pump, the rig pump and back to the kill line..

Fig. 2. Swabbing and surging in the delicately balanced wellbore was mitigated using a surface-operated flapper valve to isolate the sections of the well while tripping pipe.

Fig. 3. Shown in these MPD measurements, the operating window between pore pressure and fracture gradient narrowed and disappeared as the bit entered the Quartzites de Hamra reservoir zone.

A single high-speed BHA and bit were used to drill the entire 191-m (630-ft) section. As drilling progressed, the upper limit of the window was reduced following an exponential trend. Fluid losses were controlled by reducing the ECD.

At about 2,440 m (8,000 ft) MD, the lower and upper MPD window limits converged, Fig. 3. Losses were managed and drilling continued. At this point, an option to shift from MPD to underbalanced drilling was considered but rejected due to environmental restrictions associated with flowing the well while drilling.

At 2,486 m (8,156 ft) MD, drilling was concluded due to a combination of increasing losses, simultaneous gas influx and the increasing risk of total losses to an underlying Hamra fault.

REACHING NEW TARGETS

The MPD operations successfully drilled about 630 ft of open hole without a major problem, despite the extremely narrow operating window and the demand of managing both losses and kicks simultaneously. In drilling what had previously been an impossible well, the MPD operation also enhanced safety and environmental considerations. The performance laid the groundwork for expanding MPD drilling in Nezla Field in particular and Algeria in general.  

ACKNOWLEDGMENTS

This article was prepared from SPE 138579 presented at the Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, Nov. 1–4, 2010.

THE AUTHORS

Khelil Kartobi is the Head of Drilling Services and the Geomechanics Project Manager for Sonatrach’s onshore oil and gas fields. He has 18 years of diversified experience and holds a BSc degree in civil engineering. Mr. Kartobi has held many senior positions at Sonatrach, including more than 10 years in research and development. He has authored many technical papers and has carried out numerous reservoir and geomechanical studies.

Hani Qutob is the Reservoir Engineering Manager at Weatherford International Ltd.’s well engineering center for the Middle East and North Africa (MENA). Before holding this position, he served as the Principal Advisor for Reservoir Engineering in the company’s Controlled Pressure Drilling and Testing division. Mr. Qutob has 32 years of diverse international experience with ADNOC, ADCO, ExxonMobil, Shell and Weatherford. He holds BSc and MSc degrees in petroleum engineering.