This paper discusses the operator's use of pressurized mud cap drilling (PMCD), a form of Managed Pressure Drilling (MPD) technology, to successfully capture reserves in Qatar's North Field that were not accessible with conventional drilling operations. While drilling off one of the platforms, the operator encountered faulting, vugular porosity, and Karst features in one particular carbonate sequence that led to the total loss of returns, which could not be controlled with lost circulation material or cement squeeze operations. After reviewing the drilling alternatives, the operator determined that PMCD was an enabling technology to drill through the problematic lost circulation interval in the 12¼-in. hole section above the reservoir. Risk assessments confirmed that PMCD could be conducted both safely and effectively utilizing a rotating head (RH) rigged up on top of the existing well control package. The North Field platforms are located in the offshore Arabian Gulf and provide unlimited access to seawater. PMCD requires injection of potentially large volumes of fluid down the drillpipe and by the casing / hole annulus. Since seawater was abundant, it was the consensus fluid of choice. A review of the formations drilled in the 12¼-in. hole section confirmed clays were not present and that borehole instability would not be a concern. In addition to reducing operational complexity and trouble time, the use of PMCD in this case was also driven by the operator's drilling performance management process which dictates that performance limiters be identified and extended following a specific process. Consequently, this application of PMCD was structured to maximize footage per day rather than only address the lost returns costs. The paper discusses both the lost returns management and the associated efforts to maximize performance gains. The paper will address PMCD well control and injection equipment requirements as well as the drilling and liner running operations on the first well. The area geology and the field's history with lost returns will also be discussed. Introduction Qatar's North Field is located in the Arabian Gulf and is the world's largest non-associated gas field (see Fig. 1). All drilling operations are conducted with jack-up drilling rigs in water depths that average 225 ft. The stratigraphy and a typical wellbore configuration are shown in Fig. 2. Most wells are quite similar in terms of lithology, hole size, casing configuration, and casing setting points. Aside from one vertical data well at each platform location, all wells drilled by the operator are approximately 60° S-shaped directional wells with an abbreviated drop section into the reservoir. Several horizons are prone to intermittent to complete lost returns due to fracturing, vugular porosity, and Karst features. Karsts are void spaces in rock created by dissolution and / or erosion of the carbonates. The size of a Karst can vary from 1 cm up to the size of a cave. It is quite common for the drillstring to drop 1 ft or more when encountering these horizons, as is the case in similar carbonate sequences around the world. Reducing losses to drill ahead safely using lost circulation material and cement squeeze operations have proven to be expensive, time-consuming, and only partially effective. When deemed necessary, the operator has used floating mud cap drilling (i.e., drilling with a static fluid column in the annulus) for short sections through these problem intervals prior to attempting any lost returns remediation work. Drilling an entire section length with total losses had not been attempted due to the higher risk of mechanically sticking the drillstring from cuttings fallout and the complications imposed on well control management.
A workflow that combines optimization of the drill string and bottomhole assembly (BHA) design during well planning and then applies advanced surveillance tools to a well-trained drilling crew yields reduced vibrations, higher drilling rates, and less trouble cost. This methodology is based on the premise that an efficient drilling operation requires optimized tool designs, advanced diagnostics using real-time drilling parameters, and onsite training of efficient drilling practices and the proper use of rig control systems. The use of efficient modeling procedures to compare alternative drill string and BHA designs provides valuable insights into the string and tool selection process. A method to select the optimal stabilizer contact locations for the BHA tools helps to avoid lateral vibration dysfunctions, and a torsional vibration model can quickly evaluate the resistance of alternative string designs to harmful torsional stick-slip vibrations. Provided the proper hardware, a well-trained driller can be more effective with automated drilling performance evaluation tools that provide real-time drilling parameter recommendations based on optimizing Mechanical Specific Energy (MSE), torsional vibration stick-slip severity, and Rate of Penetration (ROP). BHA lateral vibrations modeling is field-proven and has been applied globally. One case study will show an application of the model to select a BHA design with specified rotary speed sweet spot. The torsional vibration model can be used in both a design process and in a real-time surveillance mode. In one case study, stick-slip vibrations were too severe to drill ahead with a tapered string design that was selected to lower the equivalent circulating density (ECD). The model helped identify the increase in stick-slip resistance obtained by substituting a portion of the smaller pipe with larger pipe. A real-time surveillance tool provides automated drilling performance analysis and makes recommendations to the driller on bit weight and rotary speed. The recommendations are based on the torsional vibration model results, operating in a surveillance mode, and the MSE and ROP. Rig control systems impact drilling dynamics and efficiency in ways that are not well understood by most drillers, and training on awareness and mitigation of these effects can avoid severe dysfunctions.
fax 01-972-952-9435. AbstractThe Beryl field was discovered in
A new fluid system (EP-NAF) has been utilized in the Malay Basin of the South China Sea to drill through highly depleted sands with a non-aqueous fluid at elevated densities. The fluid contains sized particles to both bridge and prop open fractures as they occur during actual drilling operations. Formation integrity is gained immediately and does not require additional critical path rig time.The design of the EP-NAF fluid commenced by first determining the formation integrity of the drawndown sands. The required fluid density plus equivalent circulating density (ECD) expected indicated a high potential for lost circulation as the fracture gradient was anticipated to be exceeded. A research team was engaged to determine the required fracture width to build 1.0 to 1.5 ppg of formation integrity in the sands; a particle size distribution was then engineered for the specific application.The sized particles were procured and delivered to the site. Training was conducted in the office and at the rig to educate all parties in the concept and procedural requirements. The drawndown sands were successfully drilled to section total depth (TD) with EP-NAF on several wells. Background and Well Design OverviewThe Malay Basin in the South China Sea holds multiple oil and gas accumulations, some which have been on production for several decades. Many of these mature fields still hold economic quantities of hydrocarbons but are challenged with depleted zones adjacent to formations prone to wellbore instability.A four-well infill development program was planned in the 4th Quarter 2009 / 1st Quarter 2010 in a mature field, Malay Basin (see Fig. 1). The field is located 200km offshore in 70 m of water. Several platforms were installed to develop the field which has been under production for more than 20 years. Tender Assisted Platform Rigs (TAPR's) are predominantly used in the area, in particular in this field.The planned four-well program was comprised of sidetrack candidates from existing wellbores due to slot constraints, cost minimization, and reduction of the environmental footprint. The donor wells would first need to be plugged and abandoned (P&A'd). The wells would then be drilled directionally through a series of depleted upper horizons. Elevated mud weights would be required due to wellbore stability concerns in the same hole section. The zones would be subsequently cased off. The lower target reservoir would then be drilled and completed in one hole section. The four-well program was expected to be drilled and completed in 235 days including 31 contingency days due to lost returns potential while drilling through the upper depleted horizons.This paper highlights the operational planning and effective application of EP-NAF in the field to successfully drill and complete the wells. Well Design Challenges and PlanningAll proposed wells would be sidetracked from existing donor wellbores, so extensive research on the donors was conducted. A variety of different casing sizes were used in the donors and exact cement tops were n...
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.