Emerging ultra high-pressure/high-temperature applications in downhole service have created the need for the development of new sealing materials. To address this emerging need, a series of modified polymeric materials were developed. The new material displayed strong mechanical properties below glass transition temperature (Tg). Above Tg, the material displayed stable elastomeric properties up to 400° C. The thermal rating of the material is beyond the available commercial thermoplastics and elastomeric materials. Furthermore, the Tg of the material can be adjusted from 97° C to 215° C. The material was aged in a crude oil at high temperature. Dynamic Mechanical Analysis (DMA) measurements were performed on the material before and after aging. The material displayed excellent resistance to the crude oil. In addition, API extrusion-resistance measurements were performed on the new material at various temperatures and various pressures. The extrusion resistance of the new material was superior to the available commercial elastomeric materials, including perfluoroelastomers. Thus, the material has great potential for use in emerging high-temperature sealing applications and other oil and gas applications. This paper describes the work involved in conducting this development work and test results.
Pragt, Jos (Baker Hughes) | Herberg, Wolfgang (Baker Hughes) | Meister, Matthias (BAKER HUGHES Inteq GmbH) | Clemmensen, Carl Christian (Statoil ASA) | Grindhaug, Gaute (Statoil ASA) | Hanken, Knut Johan
The Integrated Under-Reamer (IUR) was developed in 2007 in a joint project between an Operator and Service company. The tool was designed to allow for unlimited opening and closing of the tool to provide selective hole opening in unstable formations e.g. unstable shale or swelling salt. Furthermore the tool should be able to close for pull out of hole (POOH) while keeping the circulation continuously on.
To accommodate for this the tool was designed to be fully integrated into the modular bus structure of the downhole BHA. Electronics were developed to activate and deactivate the tool from downlink commands sent downhole and distributed via the communication bus to the IUR. Sensors in the IUR detect the status of the tool: such as position of the cutter blades and the health of the tool. This data is transmitted to surface using the MWD pulser. The data is displayed in real-time for immediate review by the drilling team. Additional diagnostic data are stored in memory for post run analysis.
Advanced autonomous fail safe control was designed to make sure the tool can always be closed either by downlink or other procedures to allow unrestricted pulling out into smaller hole or the casing shoe. In the case of communication problems a procedure is available for back-reaming with automatically closing the blades.
A case history is presented where a water injection well needed increased clearance to run 6 5/8?? completion screens. Using the IUR, the well was opened up while drilling from a 8 ½?? pilot hole to 9.05??. The IUR was de-activated and re-activated successfully several times during drilling the section. The operational procedure is described, and caliper data are presented. The well was completed on plan. At the end an outlook will be given on future reaming on demand applications.
Annular flow of non-Newtonian fluids remains a ubiquitous phenomenon in drilling operations but accurately estimating the frictional pressure loss with drill pipe rotation still poses a great challenge. Since annular frictional pressure losses increases the equivalent circulating density (ECD), it becomes imperative to accurately estimate the annular pressure loss in order to keep the ECD above the pore pressure and below the fracture gradient especially in deep offshore drilling where the pore pressure and fracture pressure are so close together.
When annular flows are encountered, a common practice is to calculate an effective diameter such that the flow behavior in a circular pipe would be roughly equivalent to the flow behavior in the annulus. This equivalent diameter definition replaces the diameter term in the friction factor, effective Reynolds number and Taylors number equations used for pipe flow thus resulting in different frictional pressure loss estimation. As a result, the selection of appropriate correlation for the respective fluids, flow regimes and putting into consideration pipe rotation has become important but has received very little attention.
In this study, the seven different equivalent diameter definitions used for estimating frictional pressure losses in an annulus were reviewed and theoretical analysis were performed on experimental data obtained from literatures to determine the effect of these definitions on wellbore hydraulics. Pressure loss ratios (PLR) which relates pressure loss with pipe rotation to pressure loss without pipe rotation weredevelopedfor each equivalent diameter definitionusing dimensional analysis techniques. These hydraulic models combined with conventional frictional pressure loss estimation were tested with experimental measurements to determine the model with an equivalent diameter definition that best predicts frictional pressure losses for power law fluids.
Geomechanics and hydraulics modeling are commonly used to optimize drilling performance and to reduce non-productive time (NPT). The geomechanics model indicates safe mud weight parameters, optimum casing points, and wellbore stability analyses. The hydraulics model simulates the wellbore and drilling fluid parameters to optimize the flow rate and rate of penetration (ROP) within equivalent circulating density (ECD) constraints. Real-time drilling data are used to update the models: the pore-pressure/shear-failure gradient and fracture gradient boundaries for geomechanics; and ECD, circulating system pressure drops, and annular cuttings load parameters for hydraulics. Each real-time model strives to ensure that operations are optimal, safe, and cost effective, as well as to provide updated models for future planning purposes.
This paper focuses on collaboration between geomechanics and hydraulics analysts in the planning, drilling, and post-drilling phases of the well. A geomechanics model determines the safe mud weight operating window and casing points, whereas the hydraulics model simulates ECD for defined mud properties, drilling parameters, and wellbore geometry. A synthesis of the two models enables the previously mentioned information to be compared and merged before spudding the well. Real-time collaboration between models enables each model to be updated with pertinent information from the other, ensuring that drilling operations are performed within optimum mud weight and ECD constraints. The geomechanics model can use real-time ECD data from the hydraulics model when a pressure-while-drilling (PWD) tool is not being used. In turn, the hydraulics model requires updating when the safe mud weight limits are being exceeded. The two models can each use information from the other when performing the post-well analysis and planning for the next well. Both models are valuable tools when used individually, but they become powerful, superior companions when used in conjunction with one another.
Drilling operations are conducted within a pressure window bounded on the lower side by the pressure of the formation fluids exposed in the open hole and on the upper side by the fracture resistance of the formation matrix. The narrowing
of this operating margin, as experienced in deepwater environments, increases the technical challenges associated with drilling operations. Typical challenges include a sharp reduction in the maximum allowable open hole drilled depth,
well control and exposure to difficult kicks, well breathing or ballooning, the risk of wellbore losses and a requirement to install multiple casing strings to get to TD.
This paper examines the phenomenon of narrow margins in deepwater, the conditions that drive it, and presents a holistic assessment of the available geological, geophysical, engineering and technology solutions for mitigating narrow margin
drilling (NMD) conditions. The solution concepts are indexed into a newly developed model called the NMD Solutions Matrix which introduces an NMD intensity scale that provides a measure of the degree of difficulty that can be expected in a well as a result of narrow margin conditions.
The applicability of the model is demonstrated in a history match of three industry case examples in two deepwater regions in the world where NMD conditions were encountered and mitigated. The NMD solutions matrix was also applied to a DW project in the planning phase which yielded insights that more clearly articulated the exposure in the project. The analyses indicate that the model, as a planning tool, has the potential to sharpen the awareness of possible challenges and enable upfront mitigation measures to reduce their impact during execution. Its application thus offers strong potential to positively impact drilling effectiveness in deepwater and yield or save considerable value in these high cost operations.
Deepwater developments are very high cost ventures in complex reservoir environments. Acquiring insight into the reservoir inflow distribution and location of water inflow using conventional technology, such as production logging tools, is very problematic in the deepwater environment where wireline intervention into live wells is a major risk and cost.
Intelligent chemical tracers are an emerging technology that provides insight into the inflow distribution without intervention operations or major alterations to the completion design. The tracers consist of unique chemical compounds that are combined with unique polymer formulations into a matrix that resembles strips of plastic. The matrix is designed to release the tracer when contacted by the target fluid, either oil or water.
The matrix strips are deployed with the initial completion installation at strategic locations in the completion so that fluids entering the completion contact the matrix. At the surface, samples of the produced fluid are acquired and analyzed for the presence and concentration of each unique tracer that has been deployed in the completion. The concentration data is plotted vs time or produced volume. Analysis of these plots can yield answers to very valuable reservoir management
questions such as:
- Are all the intervals producing?
- What is the relative contribution of each interval?
- Where is water break-thru occurring?
Deepwater completions are frequently completed with sand screens. The typical sand screen design contains spaces where the tracer can be integrated without any changes to the design. If the screen design is not readily compatible with the matrix strips, specially design tracer carrier mandrels can be added to the completion.
The passive nature and very low risk of deploying this technology is very attractive in deepwater wells.
This paper reviews the fundamentals of intelligent tracer technology, methods of integration into deepwater completions and some field examples previous deployments.
The Hadrian-5 prospect in the United States (US) Gulf of Mexico's Keathley Canyon 919 block was drilled by the operator in ~7000-ft water depth as one of the first Gulf of Mexico wells drilled after the deepwater moratorium. This exploration well was permitted under the new regulatory requirements of the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). These new requirements included additional blowout preventer (BOP) certification and testing, incorporation of selected API recommended practices, and certification of the well design by a registered professional engineer.
In addition to the well design regulations, BOEMRE required operators to calculate a worst-case discharge scenario and develop plans to contain that scenario. Well containment plans were developed that included the newly-formed Marine Well Containment Company's (MWCC) response capabilities.
The well was drilled between March and August of 2011 to a total depth (TD) of 19,631 ft and encountered several hydrocarbon intervals that were safely managed. The rig selected for this well was the dynamically-positioned (DP), Maersk Developer semisubmersible.
This paper describes the planning, permitting, and execution of this challenging well. Topics covered include:
• New permitting requirements for federal waters in the US
• Worst-case discharge scenario and impact on casing design
• Elimination of trapped annular pressure via well design
• Minimizing vibrations in the tuff formation of the Hadrian mini-basin
• Managing the uncertainties associated with sub-salt formation pore pressures
• Drilling and casing mobile tar zones
The well was drilled and evaluated in a safe manner with no significant incidents even though the geologic formations encountered were different than predicted.
Buckling of tubulars inside wellbore has been the subject of many researches and articles in the past. Evidences in the laboratory and in the field have shown that existing buckling criteria (sinusoidal and helical buckling) have to be challenged,
as they fail to predict the onset of buckling phenomenon in complex or unconventional wells drilled today. Indeed, existing buckling criteria assume generally that the wellbore is idealistically perfect without any dog legs. Recent advancements in drillstring mechanics modelling has demonstrated that dog legs, friction and rotation affect greatly the buckling phenomenon. Buckling does not imply necessarily failure neither lock-up, but indicates the onset of a condition that may generate poor drilling performance that could lead to failure or lock-up. In this paper, one proposes a new buckling severity index that quantifies the severity of the buckling phenomenon enabling drilling engineers to take appropriate decision.
A fully validated numerical buckling model has been used to derive a new buckling severity index based on the risk of drill pipe failure or lock-up. This index ranges from 1 for acceptable buckling condition with low risk of failure, to index 4 for
severe buckling with high risk of failure or lock-up. This new buckling severity index has been compared to well-known sinusoidal and helical buckling loads in a few case studies, and demonstrates that past buckling criteria should be used very cautiously.
This paper proposes an update of past conventional buckling criteria in recommending a new buckling severity index that enables to quantify the risks of failure or lock-up in unconventional and deviated wells. These new results presented in this
paper should improve significantly well planning and operational procedures to drill and operate increasing complex wells.
Good perforating design is essential in maximizing the value that can be pulled from the reservoir. Poorly-planned and/or executed perforating strategies in high-pressure, deep-water wells can easily increase operational costs and reduce production and revenue streams.
With the increased demand for oil and gas over the last decade, operators have been forced to explore deeper to find the most prolific reservoirs to meet this growing need. In the U.S. Gulf of Mexico, these deep-water opportunities have required constant improvements to equipment and services to increase their technical capabilities for performing in more critical environments while minimizing non-productive time (NPT). Higher shot densities, propellants, larger perforating guns, electronic firing heads, shrouded assemblies, and dynamic shock modeling have been used to meet these new challenges.
A major problem with these deep wells is the increased cost it takes to develop them. The use of more powerful perforating systems to increase flow area is required to maximize well productivity and recoup this cost. With the use of such systems comes the additional explosive load and the difficulty in predicting dynamic wellbore behaviors that could cause tubulars to burst, collapse, bend, buckle, and shear, as well as tubing to move excessively, packer seals to fail, and packers to unset as perforating guns are detonated.
Understanding and mitigation of dynamic events at gun detonation, in addition to solid loading imparted to the tubulars, packers, and other completion hardware in the perforating assembly, were needed if the industry was to continue exploring new frontiers with complex challenges. A high-confidence level was needed to use these larger gun assemblies to go forward with these well completions without incurring NPT.
This paper discusses a successful execution of a high-pressure, deep-water shoot-and-pull job with a custom-designed bottomhole assembly to address casing integrity challenges and the dynamic shock-modeling software program that evaluates the mechanical integrity of all well components.
With well depths more commonly surpassing 30,000 ft below the mudline and ever-increasing water depths, exceedingly high-pressure environments present a new and challenging frontier for both operators and service companies. These new environments demand advances to existing technology to endure such pressure extremes while also accurately positioning the wellbore in the reservoir and obtaining critical geological information as the well is drilled.
A recent example in this pressure regime in the deepwater Gulf of Mexico will be reviewed. Pressure limits of the currently available technology are extended while successfully meeting drilling and evaluation goals. The drilling and evaluation technologies delivered real-time formation pressure and geological information, along with continuous directional control, enabling the operator to make vital decisions while drilling and for sidetrack evaluation. This real-time decision-making capability reduced the time required to execute casing point selection and subsequent sidetrack plans. Emphasis is placed on the need for operators and service companies alike to focus on thorough pre-job planning while paying close attention to complete system requirements high-pressure evaluation tools and detailed reviews.
Newer drilling opportunities, particularly in the deepwater arena, involve operating in extreme environments such as ultra-high pressures, and demand different approaches to ensure flawless execution. This paper presents the variety of challenges, critical success factors, and lessons learned when drilling these ultra-high pressure wells in the demanding waters of the Gulf of Mexico. With downhole pressures approaching 30,000 psi and ever-increasing rig costs, the need for dependable drilling systems and integrated advanced formation evaluation technology is needed now more than ever.
The case results showcase the ability to set a new performance standard, extend the conventional operating envelop farther, and deliver answers while drilling.