Re-development drilling at Shell's Ram Powell prospect in the Gulf of Mexico targets profitable delivery of remaining hydrocarbons present in lower-volume reservoir pockets. Marginal economics put a strong focus on efficient operations, which are complicated by the technical challenges posed by severely depleted reservoirs (up to 6,000 psi differential pressure) that can only be accessed by drilling extended reach (ERD) wells. Specific challenges that had to be overcome in drilling recent Ram Powell wells include negotiating very narrow drilling margins, preventing major non-productive time associated with well control, lost circulation and stuck pipe events, and drilling the wells at optimum efficiency and favorable economics. This paper discusses the integrated operational plan that the Ram Powell team employed to successfully drill four recent ERD development wells and two slim hole sidetracks through substantial depletion while becoming one of the best-performing offshore operational teams in Shell. Specific tactics discussed include:a fit-for-purpose hole cleaning program for ERD and depleted wells;a mud weight and ECD strategy that exploits the naturally existing stress cage;an effective method to raise fracture propagation pressures in case of losses in induced or natural fractures;the use of flat-rheology synthetic-based mud to minimize barite sag and reduce ECDs;addressing the underestimated effects of temperature, annular pressure fluctuations and exposure time on wellbore stability and lost circulation;contingencies to deal with well control issues during a catastrophic loss;dealing with detrimental vibrations during depleted sand drilling Introduction Further development of the mature Ram Powell prospect (Fig. 1) faces the same challenge as seen in many brown-field developments around the world: how to extract remaining hydrocarbons in place in low(er) volume reservoirs in a cost efficient way? The dilemma here is that whereas it is difficult - if not impossible - to justify high cost wells from an economical standpoint, rather complex wells are required to access the oftentimes poorly accessible reservoirs scattered about the prospect. Main elements of complexity are the extended reach character and associated directional complexity associated with these wells, as well as the fact that they are no longer drilled under pristine reservoir conditions. Usually, historical production has led to significant reservoir depletion, leading to significant changes in pore-pressure and associated geo-mechanical changes. The challenges we were faced with at Ram Powell were in many respects unique. Ram Powell was one of the very first deepwater developments in the Gulf of Mexico1,2. As a result, at Ram Powell we are further into the field's production lifecycle than in many other Gulf of Mexico prospects, experiencing drilling problems that have rarely been seen before or experienced in similar severity. Moreover, a unique challenge was presented to the team by making the number of wells to be drilled in the re-development campaign dependent on the well delivery execution efficiency achieved. Achieving operational excellence thereby translated directly in access to more drilling and production opportunities. In the following, we will highlight how the Ram Powell team met the above-mentioned challenges, achieving a high degree of operational proficiency that made it one of the best performing teams in Shell E&P Co. We will discuss the nature of depleted sands and the challenges associated with drilling them, and present the elements of the systems approach that was adopted to drill highly successful wells. Depleted Drilling Challenges at Ram Powell Brown Field development from fixed structures presents complex drilling and completion challenges. The first stage of production of the primary targets, usually better-developed and higher-volume reservoirs, has usually produced a significant level of depletion. Further reserve recovery now requires penetration of these depleted zones with drainage points at much greater step-out than the original wells. This is the situation we face at Ram Powell.
Factors that affect downhole temperature while drilling (TWD) were modeled with a comprehensive in-house drilling mechanics and hydraulics model to help explain field observations in a GoM deepwater well. In a long, near-horizontal well section, the TWD from measurement while drilling (MWD) was much hotter than the surrounding formation temperatures, an important issue due to observed dependence of reduced bottom-hole temperature (BHT) and lost-circulation events, and also effects on downhole tools and non-productive time (NPT.) The model used is an in-house suite of drilling modules capable of modeling hydraulics, torque and drag, drillstring dynamics, and their interactive effects. Heat generation and temperatures are calculated in a coupled manner, by considering factors that include:○Mud-formation heat transfer and mechanical friction of the drillstring against the formation/casing wall;○Heat from pressure drop across bit nozzles, and the mechanical rock cutting action of the drillbit;○Friction in all drilling situations - making hole, tripping etc, depending on annular clearance;○Heat generation from mud-motor operation and operating inefficiencies. Results indicate that the rotary speed is very important; the higher the RPM, the more the BHT increases. The annular clearance is also a strong factor; the less the clearance, as in casing/liner drilling (CLD) or from tight-clearance downhole tools, the higher the BHT. Other factors in varying degrees of importance are flow rate, mud type, and weight on bit. Results of this work will support on-going attempts at deepwater NPT reduction. Introduction and Background Deepwater drilling is fraught with challenges, including borehole integrity and lost circulation. Investigators (Ref. 1–3, among others) have identified temperature effects as contributing to hoop stress increase and lost circulation mitigation. This is important because in tight drilling margins, ECD management within the pore-pressure/fracture-gradient window can be difficult, and one may possibly resort to novel methods of increasing the fracture gradient. In this paper, we have used a comprehensive in-house drilling mechanics model, along with field data and published experience, to investigate factors that affect well BHT with a view to potentially controlling these factors in order to manage the BHT and reduce lost-circulation events. The example well is in deepwater Gulf of Mexico (GoM) where relatively cold formations often experience lost circulation. Fig. 1 illustrates this vividly where mud losses were observed in zones with reduced temperature, all other factors remaining the same. Fig. 2 shows a temperature-trend match for a section of the well with TWD data. The data scatter is related to pipe connection events, rotating and non-rotating modes, changes in circulation rates, etc. On the other hand, formation temperature decrease through salt zones helps reduce salt movement (creep) and tar flow. Though critically important to NPT management in subsalt wells, the low-temperature effect along with salt-induced casing collapse is outside the scope of this paper. Work is underway on these technologies.
In September 2010 a decision was made to expand the current Mars field development with a second 24 slot TLP structure in a water depth of 3000 ft. This new development includes higher pressured deeper pays below the existing brown field Mars pays. The new structure will install wells with multiple casing strings across stacked sand packages that are both depleted and virgin pressured ranging from 10,500 ft to 23,000 ft TVD in depth. This in combination with other challenges such as extremely tight annuli clearances, depletion zones greater than 5000 psi, multiple stacked sands at varying degrees of depletion, and risk of borehole stability failure/ballooning presents a unique set of zonal isolation challenges that requires proactive novel approaches and design strategies. Zonal isolation is a regulatory requirement and a key component of project success in order to secure maximum field recovery and future wellbore utilization within the estimated field life.Zonal isolation methodology and design does not have a single focus but explores all parameters that affect placement and isolation while not losing focus on striving operational simplicity. This paper discusses the engineering approach to zonal isolation requirements in a highly challenging environment utilizing a step wise methodology with increasing complexity and also elaborates on how this approach led to the identification and ultimately the development of new technologies.Design methodologies will be discussed as well as resulting technologies identified as a "must haves" for development to ensure maximum probability of zonal isolation success. Technologies discussed will include reverse cementing tools, 50 (ϩ) year seals for stage collars, and connection requirements. Statement of Requirements (SORs), basic tool descriptions, and preliminary results of these developments will also be included. Discussions on why certain placement techniques or approaches were not integrated into the zonal isolation project plan will also be discussed. OverviewNumerous design challenges must be managed to ensure wellbore objectives, lifecycle wellbore integrity, robust future utility and top quartile execution performance is achieved for Mars B Olympus direct vertical access (DVA) wells. New regulatory requirements and design conditions have led to the required use of
New regulatory requirements and design conditions introduced in recent years have led to the use of higher strength tubulars in the majority of Deepwater wells in the Gulf of Mexico. To achieve the new design requirements, the use of non-conventional casing sizes, grades and weights different than those traditionally used and available in the industry are required. The use of thicker wall tubular has consequently resulted in geometrical constraints and tighter annuli clearances in the wellbore driving new connection design requirements and selection criteria to meet overall well objectives. The new design conditions require innovative connection design to meet or exceed the collapse strength of pipe body rating. As part of the Shell Mars B project, the Olympus TLP DVA team championed the development and qualification of multiple connection types to meet the project requirement and for overall portfolio usage. As the number of connections to be designed and qualified is substantial, a pragmatic and systematic testing philosophy and strategy was developed for the Mars-B project TLP DVA wells. This paper provides a high level overview of the connection selection challenges, the systematic process adopted to streamline connection development, testing and qualification. It will also discuss some of the challenges in connection design to meet well requirements and qualification process. The scope includes static connection design for strings installed below the subsea well head, as well as, dynamic connection design on strings that are installed in the water column. Both connection designs require sealability qualification and assurance. Dynamic connections require additional fatigue design and qualification. Rigorousness of sealability and fatigue testing is appropriate to the environment of which it will be subjected throughout the well and the 50 year field life.
The Mars-B project is Shell's sixth GOM TLP development and demonstrates Shell's commitment to GOM. The Mars-B project is aiming to unlock resources over the next 50 years through the deployment of a new 24 slot TLP structure (Olympus TLP) and additional subsea infrastructure for the West Boreas/South Deimos fields. The Olympus DVA rig is a novel platform drilling rig designed specifically to meet the execution requirements of complex Olympus DVA well designs. The well design and associated equipment must accommodate the 50 year design life, the longest design life of a TLP in Shell's history. This is the first development to incorporate post-Katrina environmental design loads and new regulatory design requirements. Project challenges include numerous technical challenges pertaining to well designs for 24 DVA wells targeting over 50 horizons spanning 10, 500 ft TVD to approximately 25, 000 ft TVD encompassing both highly depleted brown field and deeper virgin pressure formations. The Olympus DVA well trajectories range from near vertical to high angle extended reach both through sediments and through salt penetrations. Rig and surface facilities must be designed to address multiple challenges present to ensure well and facility integrity, reservoir isolation and desired well construction objectives are met. This requires successful development and deployment of novel technologies and world class systems. The design requirements have resulted in an evolution of traditional well designs which in turn drives novel rig and surface facilities requirements. A high level overview of the design challenges and the resulting surface equipment requirements will be discussed. This includes rig equipment requirements to meet the specified execution directives, the development of an innovative drilling riser concept, added systems optimization to increase safety and overall execution efficiency.
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