U-Shaped Re-Entry Drilling Revitalizes Depleted Reservoirs Offshore Congo
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Against the background of a low-oil-price environment, a redevelopment project was launched to give a second life to a shallow, depleted, mature offshore Congo oil field with viscous oil (22 °API) in a cost‑effective manner. The solution selected was to drill U-shaped side tracks (inclination at total depth=115°) from the original boreholes on an existing platform at a water depth of 60 m. The objective was to create a second drainage area. The project team used innovative, low-cost techniques to overcome many challenges.
Geological Context and Objectives
Under 27 platforms (four to five wellheads each), an accumulation of heavy, viscous oil is trapped in three reservoir layers. The field was produced with a combination of cold mode followed by a period of hot mode from steam injection. The consequence is a depleted (0.3‑sg) and highly steam-fractured reservoir where fluid loss presents one of the primary challenges for infill development.
The pilot project consists of re-entering the current producers and then deepening them in a U shape to access the same shallow reservoirs more than 200 m away from the initial production leg. All reservoirs share the same water table identified below an impermeable formation underneath the target layers. To avoid water breakthrough, the trajectories were planned with up to 18°/30 m to prevent the well from entering the water-bearing layer, with minimum 30-m true vertical depth standoff from the oil/water contact.
Well Design and Architecture
The well architecture is selected to match the existing mother-well construction. All selected re-entry candidates are producing wells showing the following well architecture:
- A 9⅝-in. casing set as intermediate casing at approximately 100 m measured depth (MD) below the rotary table
- A mixed string composed of cemented blank 7-in. casing and uncemented 7-in. slotted liner in front of the pay zones. An external casing packer (ECP) was installed between the two strings, and a cementing job was performed above the ECP. The float shoe at the bottom, therefore, was uncemented and prone to be untorqued during re-entry
- The completion system consisted of progressive-cavity-pump or sucker-rod-pump strings, depending on the wells.
To fulfill the geological and reservoir objectives, the wells were re-entered by drilling a 6-in. hole section from a 7-in. float shoe to the U-shaped total depth before a 4½-in. liner was run. The sandface completion evolved slightly from the first two wells (blank perforated) to the last three wells (slotted liner).
Selected Architecture. During the first campaign (two wells), a 4½-in. blank liner with a standard liner hanger was set inside the 7-in. slotted liner. The pipe was perforated on tubing-conveyed perforations in front of the pay zone (uphill section) with 2⅞-in. guns. Swell packers were installed between the downhill and uphill sections as an additional isolation barrier to the water table (Fig. 1).
The second campaign (three wells) 5 months later took advantage of the lessons gathered from the first campaign; optimization led to well-architecture modification. A mix of 4½-in. blank and slotted liners was run with no isolation features, and the liner was installed with a drop-off liner system (no slips or packer element) inside the same 7-in. casing.
Trajectory Design. The design goals included
- Reaching an approximate 110° inclination at the beginning of the uphill section in order to achieve the minimum 300-m pay-zone interval targeted. The last well of the campaign was redesigned in order to chase the limit of the rig and drilling-tools capacity with a 565-m drain length in the reservoir.
- Building as quickly as possible with dogleg severity (DLS) ranging from 15°–18°/30 m from the motherbore-hole casing shoe (at exit depth) in order to remain in the impermeable layer and therefore avoid any future water coning in the new drain.
- Achieving a smooth buildup rate at the beginning of the uphill section in order to ease the liner-running job in this part of the well.
Primary Drilling Challenges
Shallow Kickoff in Soft Formations With Mud Motor. A positive-displacement mud motor (PDM) was chosen to perform error-free shallow kickoff in unconsolidated sand. The need to use lower-cost technology and ensure sufficient standoff to the water table resulted in the selection of a bottomhole assembly (BHA) able to achieve high DLS immediately from the well exit.
Directional Planning and Weight-Transfer Mitigation. One of the major challenges raised by lower-cost U‑shaped re-entry wells is the need to drill the entire well with the mud motor with a minimum number of trips. The highly unconsolidated formation made the BHA highly prone to accidental sidetrack when tripping in, especially when rotation was required while running in (the result of weight transfer caused by high DLS at the exit, limited true vertical depth, and drags in the hole).
From the planning phase through the execution phase, directional planning was optimized continuously, followed by close review of torque-and-drag simulation and back analysis. The main lesson learned from these efforts was the impossibility of sliding after approximately 820 m MD.
In the first wells, a high buildup tendency in the rotary was recorded, making the rotary section close to total depth troublesome. After review of the BHA design, the stabilization strategy was optimized with the addition of an undergauged 5¾‑in. stabilizer behind the motor sleeve (5⅞ in.). This allowed the BHA to have a slant tendency in the rotary without compromising the DLS capability.
The successful directional planning therefore consisted of
- Use of high-DLS-capability BHA to achieve planned DLS at the motherbore exit; the objective was to create a well inclination of 90° or greater and then pull out of hole
- Ensuring a slightly slanted drilling tendency in the rotary
- Bringing the well to final inclination before MD of 820 m, having fulfilled the approximately 200-m stepout criteria
- Drilling the last 200 m to total depth in full rotary with high weight on bit and low flow rate
Formation-Loss Prevention With Thixotropic Mud System
Reservoir pressure was as low as 0.3 sg in highly permeable and unconsolidated formations. Moreover, the past steam injection performed over the field to enhance recovery of its highly viscous oil has led to the formation of huge fractures. Different solutions were explored to manage losses while ensuring well connectivity with the pay zone, including an aphron-based mud system and a thixotropic mud system. Ultimately, losses could not be mitigated with the aphron-based mud system during drilling, but the thixotropic system showed better results. During mud preparation, it was confirmed that this fluid is highly sensible to pH variation.
The thixotropic property of the drilling fluid in this solution was achieved by the addition of a mixed metal oxide agent, creating an ionic link with prehydrated bentonite in mud, allowing the fluid to show high yield point, low viscosity, and 1.03-sg weight. The high gelling property cured losses in both formation permeability and fractures.
Running a 4½-in. liner in a U-shaped well ending at approximately 110° inclination was one of the primary challenges faced during planning and execution. To increase the chance of success, it was necessary to ensure washdown (with inner string) and rotation capability. Therefore, a 4½-in. mixed liner string (blank and slotted) was run on the liner-dropoff system (no slips or packer element) with the inner string stabbed to the shoe, allowing washdown capability and high torque rating.
Because of a technical sidetrack while running liner on the first well, it was reported that the eccentric shoe was not an adequate solution for those wells because their sharp noses are prone to stick into caves, leading to accidental sidetrack (highly washable sands). Standard rounded shoes were used afterward, and the swell packers were removed.
An extensive torque-and-drag analysis was performed to assess if the 4½-in. liner could be run without rotation, thus avoiding any risk of accidental sidetrack. Also, because of expected drags, it was important to make sure that liner and tubular connections were able to withstand the torque in case rotation was needed. All liner strings were composed of 4½‑in. premium connection pipe lowered in the hole with a high-torque liner dropoff system and 3½-in. heavyweight drillpipe for weight transmission.
During the execution of the project, drag was assessed to back-calculate the friction factors and to adjust running the BHA on the next wells because trajectories were becoming more challenging. On the longest well, 4¾-in. drill collars were added. For the last and most-challenging well of the campaign, 14 4¾-in. drill collars were added in the running string. It was decided to add the drill collars directly on top of the liner.
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U-Shaped Re-Entry Drilling Revitalizes Depleted Reservoirs Offshore Congo
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