Optimum mud window prediction is very crucial for drilling any well. Accurate prediction of pore pressure, fracture pressure and other geomechanical parameters such as stresses, rock mechanical properties and finally the collapse pressure are key for designing the optimum mud window and effective well planning. Predrill predictions of pore pressure and wellbore stability become more and more challenging as the industry is moving to more and deeper and ultra-deep water wells. This is primarily becaue of lack of offset calibration together with inherent probrems and challenges associated with deep water environments. A substantial amount of non-productive time (NPT) was associated during the initial phases of drilling campaigns in the Brunei deepwater. Accurate mud weight window prediction using regional scale pore pressure prediction and geomechanical modeling clearly demonstrated a significant reduction in nonproductive times over the different phases of drilling campaigns till date. This also includes a regular update or refinement of the model as soon as new data or information becomes available. This paper presents some of the methodologies employed during well planning and construction with refinement along the way, resulting in improvement on pore pressure and geomechanical model. Our intent is to document and share our experiences and lessons learnt in Brunei deepwater well so that design and execution workflow can be continuously improved thus the well can be delivered safely and costeffectively.
Structural casing or conductor pipe provides a foundation for deepwater well and is designed to withstand the expected axial and bending loads. A very conservative design approach with worst case scenario is usually adopted for structural casing in exploration wells because the lack of information and high risk associated to deepwater operations cannot be underrated. This paper will present the evolution from a conservative to a fit-for-purpose engineering design approach. A design review with the latest interpretation of regional geological understanding derived from actual drilling experience was performed to quantify the associated uncertainties in the design phase. The result was compared with an independent analysis and validated during the actual installation performed by rig contractor. The project team supplemented this paper with a case study by sharing the conductor installation results from the jetting operation. In the early stage of deepwater exploration wells in Southeast Asia (SEA) region, many operators set their first string or structural /conductor pipe at around «80 m below mudline. This is a normal industry practice adopted from experiences in the GOM deepwater operation or operators' own experience in their deepwater field. This structural casing is generally jetted down with internal jetting BHA and drilled in riserless mode to the predetermined depth. This first string will not be cemented, and a subsequent surface casing will be installed and cemented to seabed. These two (2) strings will provide the foundation for a deepwater well to withstand the expected load, which are axial loads and bending loads. The conservative design generally uses a large size structural pipe like 36 in. OD with wall thickness from 1.5 in. to 2.0 in. WT. The second surface casing typically uses a large size pipe like 20 in. OD with moderate wall thickness. A weld-on connector are generally used for both structural and surface casings to accommodate the expected axial and bending load resulting from the installation of BOP and marine riser. The paper will describe the progression and transformation from the conservative to a fit-for-purpose design by optimizing the structural casing setting depth, its wall thickness and employing slim well architecture specifically for shallow well objectives below mudline. The most significant finding is that the slim design has proven to be suitable and was successfully installed in three (3) ultra- deepwater exploration wells in Brunei. This paper also will share the Company's experience and observation during the structural conductor installations to achieve efficient execution during jetting operations. The novelty of the fit-for-purpose design is in the ability to change the design norm resulting in substantial cost savings to the company and meeting the well objectives.
This paper discusses novel approaches that resulted in the successful drilling, completion, and production from shallow and unconsolidated clastic reservoirs, offshore Brunei. As a result of these new approaches, detailed planning, continuous and open communication throughout the development project, the candidate well was drilled successfully, with the directional, well placement, and completion requirements being achieved. In addition, the application of new sand control technologies coupled with specifically engineered procedural solutions assured sand-free production at a rate above expectations. Introduction The Champion oil and gas field, offshore Brunei, is a multibillion barrel field that was discovered in 1970. Because of the thin-bedded nature of the clastic reservoirs, the field is subdivided into multiple stratigraphic units and fault blocks. Some of the least developed parts of the field are located in shallow [less then 400 m true vertical depth, subsea (TVDSS)] and unconsolidated reservoirs. Previous production from these reservoirs, from near vertical wells, resulted in poor flow rates. A development project was initiated to overcome the challenge of optimizing flow rates from these shallow reservoirs within strict and tight project timelines. This paper discusses the results from one well in the project. Horizontal openhole gravel packing (OHGP) methods have been accepted as a proven standard of completion for maximizing hydrocarbon productivity and minimizing formation drawdown in the petroleum industry for many years (Price-Smith et al. 2003; Law et al. 2005). Implementing sand-control measures in unconsolidated formations without impairing well productivity has been a challenging task from both a technical and an economical perspective (Price-Smith et al., 1998; Parlar and Albino 2000; Law et al. 2005). Gravel packing of long horizontal intervals using conventional gravel-pack tools presents a moderately complex fluid mechanics problem. The most commonly encountered problems in horizontal gravel packing are premature sandout and/or formation breakdown. These problems lead to incomplete placement of the gravel pack, with undesirable consequences ranging from higher completion costs to sand in surface facilities and long-term completion reliability problems (Vliet et al. 2001). Until recently it has not been possible, technically or economically, to drill and complete horizontal wells in certain parts of the Champion field because of the challenging nature of the formation and the proposed well profiles. To enhance production from these reservoirs, challenging well designs were required to allow landing the well by approximately 400 m TVDSS and have in excess of 500 m of drain section. Dog-leg severities (DLS) of around 6°/30 m would be required, in a field which is notorious for soft and unconsolidated formations, making directional control using conventional mud motors unpredictable. Due to the soft nature of the formations, the drilling rate of penetration (ROP) was expected to be very high. This added to the challenge of being able to land the well in the 7 m true vertical depth (TVD) best quality layer within the reservoir by using logging while drilling (LWD) technologies.
Shallow gas hydrate zones are present in some deepwater fields. During production, the shallow hydrates may dissociate due to heat-up of the near wellbore formation, which can extend radially to several meters from the wellbore. This can compromise structural integrity of the well (particularly structural strings), cause subsidence, and impact subsea equipment installations. This problem is well known, and has been addressed in the literature. An enthalpy-based transient thermal simulation is required to determine the dissociation front. Further, post-dissociation formation mechanics and well integrity assessment are complex, requiring numerical approaches such as Finite Element Analyses. In this paper, we present an approach that allows a preliminary assessment of the severity of the impact of dissociation on well integrity, so that a more complex assessment may be undertaken only for severe situations. The main objectives of the preliminary assessment are: to model hydrate dissociation front and the radial extent of dissociation as a function of depth; evaluate response of formation to this dissociation; analyze mechanical response of the well to the modified mechanical properties within dissociated zone; and confirm well integrity. The paper describes the approach, and introduces two thermal metrics to assess the likely severity of the integrity impact of hydrate dissociation. Using these metrics, the need for a more detailed analysis can be determined. Further, load analysis and integrity checks of the structural strings and the wellhead that can be performed as part of the preliminary assessment are discussed. An illustrative example is used to demonstrate the approach.
The objective of this paper is to present the planning, simulations, laboratory testing and operational results for the initial deepwater deployment of a new cementing technique which utilizes a "heat sweep" of warm seawater circulated inside the casing after cement placement to accelerate early compressive strength development. This technique is made possible through a novel stabbed-in inner string cementing technology which also reduces operational risk for the cement job and saves rig time by eliminating conventional cement shoe tracks. The pre-project planning included comprehensive thermal simulations for placement of the "heat sweep", the 22″ surface casing cement job's temperature profile over time and the corresponding effect on compressive strength development. Additional laboratory testing of the "rig-blend" cement to be used in the well was also completed with and without the effect of the "heat sweep" to finalize the wait-on-cement (WOC) criteria for the 22″ cement job. Finally, a set of detailed operational steps were formalized in the drilling program. The 1000 m (3281 ft) 22″ surface casing cement job at 1532 m (5026 ft) water depth was successful, and several best practices and lessons learned were recorded for the deployment of the new technologies. Highlights included preparing the "heat sweep" utilizing rig systems to the initial placement temperature of 75°C (167°F), cementing through the stabbed-in inner string system, placement of the "heat sweep" inside the casing, and recovering a downhole cement sample and temperature logger from the bottom-hole assembly (BHA). The downhole temperature logger recorded that a maximum 37.07°C (98.72°F) was delivered to the casing shoe, which was roughly double the maximum recorded environmental temperature and an exponential increase above the minimum environmental temperature, near freezing, at the mudline. The "heat sweep" generated approximately 9 times more compressive strength in the cement over 8 hours (1150.55 psi) when compared to the base case without the "heat sweep" effect (129.81 psi). This increase in compressive strength development was equivalent to a 4-hour WOC reduction to develop 100 psi in the tail slurry or a 16-hour reduction in WOC to develop 500 psi in the lead slurry near mudline. Additionally, the 22″ casing pressure tested to 2000 psi, and the shoe was drilled out in less than 20 minutes, saving 6 1/2 hours of rig time when compared to the Operator's most recent subsea well. The formation integrity test (FIT) achieved a slightly higher pressure than expected, and the subsequent 17 ½" section was drilled in a single fast run. The subject novel cementing technologies have the potential to reduce costs and drive efficiency for deepwater drilling operations. This case study presents the first deepwater application for utilizing heated seawater to help rapidly build compressive strength in a cement job after placement through a novel stabbed-in inner string cementing system.
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