Successfully Managing Drilling-Fluid Losses in Multiple, Highly Depleted Sands
- J.F. Jones (Marathon Oil Co.) | G.D. Taylor (Marathon Oil U.K. Ltd.) | R.D. Barree (Barree & Assoc.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2003
- Document Type
- Journal Paper
- 182 - 187
- 2003. Society of Petroleum Engineers
- 2 Well Completion, 1.6 Drilling Operations, 1.10 Drilling Equipment, 3 Production and Well Operations, 5.5.2 Core Analysis, 2.5.1 Fracture design and containment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.11 Drilling Fluids and Materials, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.1 Well Planning, 2.4.3 Sand/Solids Control, 1.12.2 Logging While Drilling, 1.14 Casing and Cementing, 1.7 Pressure Management, 2.2.2 Perforating, 1.2.3 Rock properties, 4.1.5 Processing Equipment, 1.8 Formation Damage, 5.2.1 Phase Behavior and PVT Measurements, 1.6.1 Drilling Operation Management, 4.1.2 Separation and Treating, 1.12.1 Measurement While Drilling, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.6.6 Directional Drilling
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Successfully drilling through depleted sands to reach deeper targets often demands a delicate balancing act between maintaining mechanical stability in normal and overpressured shales and controlling fluid losses caused by hydraulic fracturing. A host of considerations go into the planning process, including whether further production from the depleted zones is planned.
Because of the prohibitive cost of a new North Sea well, a stability analysis was performed to determine the feasibility of sidetracking from an existing well and then directionally drilling through two highly depleted sand formations with a single hole section.
The case study presented compares the original mechanical-stability and hydraulic-fracturing estimates with the actual mud weights used to successfully complete this difficult drilling operation. Descriptions of hole instability and fluid losses are presented along with the drilling fluid parameters used to combat them. Methods used for estimating formation pore pressure, in-situ stresses, and formation rock properties are also described. In addition, possible explanations for the differences between the planned and actual stability estimates are explored, with future recommendations for similar operations.
Marathon's Brae B platform is located in the North Sea, approximately 150 miles northeast of Aberdeen in 326 ft of water [556 ft rotary kelly bushing (RKB) to mudline]. Gas and condensate production at Brae B is from two distinct sand formations - the North Brae reservoir starting at +/-12,400 ft true vertical depth (TVD) RKB and the laminated Hugin sandstone layers (part of the Beinn formation) that start at +/-14,500 ft TVD RKB. The original formation pore pressure in the North Brae reservoir was approximately 6,500 psi (10.0 lb/gal) compared to original formation pore pressures in the Hugin sand layers of approximately 11,000 psi (14.6 lb/gal). At the time of this project in May 2000, pore pressures in both these reservoirs were depleted to roughly 6.5 lb/gal, or 4,200 and 4,900 psi, respectively.
For a porous formation, it is generally accepted that hydraulic fracturing pressure is partially dependent on formation pore pressure. 1,2 However, the models commonly used to predict both fracture initiation and propagation are often unable to predict the changes in hydraulic fracturing pressures caused by depletion. The authors believe this is caused more by the difficulty in predicting the data required to link pore pressure variations to stress rather than by a deficiency in the existing models. More significantly, these models typically assume no flow and thus are not valid when there is significant fluid loss to the formation.
Nearby drilling with the Ocean Nomad in 1987 identified additional deeper reserves in what is called the Upper Sleipner reservoir. Two competing plans for drilling a well into the Upper Sleipner and then bringing production back to Brae B were reviewed. The first plan called for drilling a new well from the platform, while the second plan called for sidetracking from an existing North Brae well.
The potential cost savings of drilling from an existing well were very attractive, but there were major concerns about the number and size of casing strings required. A successful completion needed a 4 1/2-in. liner at total depth. The plan called for milling a window in the 95.8-in. casing, drilling an 8 1/2-in. hole through both the depleted Brae and Beinn reservoirs, and then running a 7-in. liner before drilling into the highly overpressured Upper Sleipner. This paper deals only with what is considered the first and most critical stage of the total operation - drilling through the overpressured shales and two highly depleted reservoirs with a single 8 1/2-in. hole section.
Fig. 1 shows the basic zones to be drilled during the two stages of this operation. It was determined that a new well would be too costly, and, therefore, the following plan was recommended for the first stage (see Fig. 2).
Kill well and pull existing completion.
Isolate reservoir and orient and set packstock.
Mill window in 9 5/8-in. casing.
Sidetrack and directionally drill an 8 1/2-in. hole through the depleted Brae and Beinn reservoirs.
Drill into but not through the 65-ft regional coal shale overlying the overpressured Sleipner reservoir.
Run and cement a 7-in. drilling liner and suspend well.
Stage 2 would consist of drilling out of the 7-in. liner with a 6-in. bit through the Upper Sleipner formation to total depth. At this point, a 4 1/2-in. liner would be run and cemented and then tied back before running the completion. The two stages of this operation would be separated by a 2- to 3-month period to allow for the procurement of a 15,000-psi rated blowout preventer (BOP), wellhead, and completion equipment.
Predrill Mechanical Stability and Hydraulic Fracture Prediction
Planning a directional well through multiple highly depleted sand formations separated by overpressured shale and limestone presented significant technical challenges. Adding to this difficulty was the fact that this operation had to be accomplished with only one hole section. If two hole sections were required for the first stage, the final section would have to be drilled with a 4 1/8-in. bit, which was more challenging from a drilling and completion standpoint and, therefore, not an attractive option. It was also important to ensure careful identification of the coal shale to avoid drilling into the highly pressured Sleipner reservoir. This coal shale was only expected to be approximately 65 ft thick, so it was important to correlate to the 16/7a-30z exploration well because it also encountered the coal shale.
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