During a drilling operation, real-time analysis of surface and downhole measurements can give indications of poor hole cleaning. However, it is not always intuitive to understand how and where the cuttings are settling in the borehole, because the transportation of cuttings and the formation of cuttings beds are largely influenced by the series of actions performed during the operation. Using a transient cuttings transport model, it is possible to get a continuously updated prognosis of the distribution of cuttings in suspension and in beds along the annulus. This information can be of prime importance for taking decisions to deal with and prevent poor hole cleaning conditions.
A transient cuttings transport model has been obtained by integrating closure laws for cuttings transport into a transient drilling model that accounts for both fluid transport and drill-string mechanics.
This paper presents how this model was used to monitor two different drilling operations in the North Sea: one using conventional drilling and one using MPD (Managed Pressure Drilling). Some unknown parameters within the model (e.g. the size of the cuttings particles) were calibrated in order to obtain a better match with the top side measurements (cuttings flow-rate, active pit reduction due to cuttings removal). Using the calibrated model, the prediction of cuttings bed locations were confirmed by actual drilling incidents like pack-offs and overpulls while tripping out of hole.
Based on the calibrated transient cuttings transport model, it is thereby possible to evaluate what adjustments of the drilling parameters are necessary to stop and possibly remove the cuttings beds, therefore giving the drilling team the opportunity to take remedial and preventive actions based on quantitative evaluations, rather than solely upon the intuition and experience of the decision makers.
A tremendous amount of effort has been placed on subsea cap and containment in order to demonstrate the exploration and production industry's response to a subsea well control event. This paper will focus on the methods and processes planned to contain a subsea blow out beneath a Tension Leg Platform (TLP) in deepwater Gulf of Mexico. Response to a well control event of this type is divided into 3 major categories: 1) TLP Health and Stability Monitoring - Understanding the structure stability is key in planning the response and determining the time allowed to deploy containment assets, 2) Debris Clearing- a path must be cleared into the well pattern horizontally and vertically for the capping stack to be deployed and 3) Stack Deployment - with the TLP still floating above the well pattern the stack must be deployed laterally under the facility and onto the well. Several challenges were encountered during the design and approval of this containment method, leading to the development of alternative capping strategies, purpose built capping stacks, installation of permanent monitoring / response equipment and use of Delmar's Heave Compensated Landing System (HCLS) to accomplish these critical subsea tasks.
In the world we know today, BOP performance is in the limelight all the way from the manufacturers to governmental levels. Greater performance objectives require higher testing standards. Testing and qualification of BOP equipment as dictated by API 16A involves facilities with the capability to test BOP's in multiple environments and operating scenarios. This paper will discuss the test set up for each type of test, the criteria for acceptance and the type of facility required to perform it. The types of tests to be discussed as defined in API 16A are fatigue testing, high temperature, low temperature, stripping, hang off, sealing characteristics, shear testing etc. The paper will also discuss some of the potential future testing requirements as well as the equipment required to perform it based on industry discussions of these requirements. Finally, the paper will discuss the process by which a multimillion dollar R&D lab was developed and operated from the ground up. It's not only about capability; it's about capacity. Applying manufacturing principles to the design and operation of an R&D Test facility achieved significant gains in the quality and output of tests performed. In summary, this paper will examine the needs of a modern BOP test facility and the methods used to deliver on those needs effectively.
Value-added efforts towards determining the optimum approach to drilling challenging offshore prospects include applications of reliability centered strategy early in the planning process. The objective would be to determine the drilling method with highest probability of enabling a safe, on-time and on-budget drilling program that reaches total depth objective with large enough hole for viable production.
Reliability assessments focus on probability of successful functioning; fit for a purpose, resistance to failure, ability to perform a required function for a definitive period of time, and ability to fail well. The reliable performance of the hydraulics of the circulating fluids system itself, even if the encountered pressure environment is not within the predicted drilling margin of error, is critical for operational success.
This presentation applies Reliability Engineering skills to a HPHT prospect whose water depth and formation pressure map suggests risk of kick-loss scenarios, differential sticking, cementing challenges and TD with too small a hole. An offset well's actual experience with conventional drilling methods will be compared with an operational reliability assessment of applying some applicable variation of managed pressure drilling (MPD) on the proposed well.
Reliability theory became a creditable science during the early days of sail ships to inform investors of the reliability of a vessel to return safe & sound.1 The author proposes that operational reliability concepts remain valuable in marine environments and are uniquely applicable for the purpose of choosing the optimum drilling and well construction methods for drilling challenging offshore drilling programs.
Microhole coiled tubing drilling is a new technology that provides many added advantages but at the same time poses numerous operational challenges. This manifests itself in a number of ways, all of which adversely affect the efficiency of the drilling process. These problems include increased wellbore friction, poor hole-cleaning, tubular failures, and associated problems during tripping operations. Presently conventional torque and drag models are used to calculate drag forces and surface loads during microhole coiled tubing drilling. However, these estimates might be under conservative. Therefore, an improved model and more comprehensive analysis are required.
Conditions expected during microhole coiled tubing drilling are completely different from those encountered during conventional drilling. Further complexity is added when the wellbore is undulated. This paper describes a new analytical model for estimating drag forces by assuming that pipe in the horizontal portion follows a sine function wave due to residual bends and snubbing force. In addition, the model takes into account when the wellbore is also tortuous. Fluid viscosity (an important force in the microhole) is also included so we can calculate appropriate surface loads in addition to drag. This study concludes that besides wellbore inclination, curvature, and wellbore torsion, parameters such as wave length and contact area also influence the results. This paper documents the comparison between the predicted mathematical simulation results with actual data from wells describing the accuracy and applicability of the model. The analysis results and comparison are presented along with three examples.
Jervis, Anthony (Chariot ) | Kemper, Julia (Chariot ) | Richards, Martin (Chariot) | Taylor, Mathew (Chariot ) | Clarke, Colin (Senergy) | Turner, Marcus (Schlumberger) | Kelsall, Neil (Schlumberger) | Puech, Jean Claude (Schlumberger)
Rank wildcat wells in Ultra deepwaterD- present some of the greatest challenges today. Decision making during drilling is challenging due to a lack of offset well data. 3D Surface seismic data has significant uncertainty from the translation of two-way time to horizon depths which further induces risk into the predrill pore pressure model.
This paper looks in detail at how the utilization of a high-tech logging while drilling suite in the execution of a rank wildcat enabled key drilling decisions to be made, reducing risk and time vs. depth plan the well.
Seismic while drilling technology guided drilling in each section from spudding to total depth by allowing up to 600 m look ahead. This reduced target depths uncertainty from +/-100 meters to less than +/-5meters. Furthermore it permittedallowed this complex S-shaped well trajectory to avoid accidental penetration into the first target avoiding well control situation, placing the 13 3/8?? casing shoe safely above the first target, 80m shallower than planned. This ensured an increased mud weight window for the 12.25?? section.
In the 12.25?? section, Formation Pressure While Drilling Technology was added to the Seismic and Sonic technologies to calibrate the pre drill pore pressure model. This was critical due to a narrow mud weight. The acquired formation pressures coupled with while drilling petrophysical data allowed for the pore pressure to velocity transform and normal compaction trend lines to be calibrated reducing the uncertainty in the pore pressure model ahead of the bit. Uncertainty in depth of targets and modeled pressure ramps ahead of the bit were further reduced with the Seismic data.
This paper builds on the information contained in part 1 and presents a general pipe-stand model. The model is based on the Fourier series solution of the energy equation for calculating the deflection and buckling condition of an inclined, non-uniform pipe stand with an arbitrary number of intermediate loads and stick-up above the top racking board. Full details of the derivation and algorithms are included in the paper. This flexible approach is used to examine more complex, practical situations including the buckling sensitivity to the position of the upper support and added loads such as tool joints or running tools racked with the stand.
Using a Fourier sine series solution avoids dealing with the less familiar higher order functions encountered in part 1 so that the algorithms can be coded using standard spreadsheet functions. This approach also increases the model's capability and practical worth, providing a tool suitable for field use. The results for loaded, uniform stands compare within 0.01% with the limiting cases represented by the analytical solutions presented in Part 1. Non-uniformity of the stand can add significantly to the number of series terms required.
Several practical examples are used to illustrate the model's application, including the analysis of stand with a heavy intermediate load where buckling occurred. The model successfully distinguishes between the buckled and non-buckled conditions.
Nwaoji, Charles O. (University of Calgary) | Hareland, Geir (University of Calgary) | Husein, Maen (University of Calgary Library - Swets) | Nygaard, Runar (Missouri University of Science & Tech) | Zakaria, Mohammed Ferdous (University of Calgary)
This paper introduces a novel LCM drilling fluid blend which has been used successfully in the laboratory to acheive wellbore strengthening results in permeable and impermeable formations for water based and invert emulsion (diesel oil) based drilling fluids.
Optimum combinations of standard LCM (graphite) and in-house prepared nanoparticles (NPs) (iron (III) hydroxide and calcium carbonate) have been established by running hydraulic fracture experiments on Roubidoux sandstone and impermeable concrete cores. Different blended fluids were used to prop open and seal fractures. The blends that gave the highest increase in fracture pressure with minimal distortion in mud rheological properties were selected for both drilling fluid type. The optimal fluid blend for water based mud was repeated using impermeable concrete core to test for consistency of result and possible application to shale wellbore strengthening.
The optimal blend (iron III hydroxide NPs) and graphite increased the fracture pressure by 1,668 psi or by 70% over the unblended water based mud with moderate impact on mud rheology. The optimal blend (calcium carbonate NPs) and graphite increased the fracture pressure by 586 psi or by 36% over the unblended invert emulsion mud with moderate impact on mud rheology. Plastic viscosity and 10 min gel strength have been noted as important markers or indicators that show when the blended fluid will give very good wellbore strengthening result. Absolute fracture sealing was noticed in two of the samples (sandstone and concrete) while running the re-opening pressure cycle which shows the excellent propping and sealing properties of the blend. A 25% increase in fracture pressure over the unblended mud was achieved in impermeable concrete core showing the applicability of the designed fluid in shale wellbore strengthening.
Future work involves field verification of the laboratory results achieved with the designed LCM blends.
Pardy, Craig (Husky Energy) | Akinniranye, Goke (K&M Technology Group) | Carter, Mackenzie (Schlumberger) | Crane, Gerry (Husky Energy) | Wishart, Lisa (Husky Energy) | Krepp, Tony (K&M Technology Group) | Foster, Brandon (K&M Technology Group)
The White Rose field and its satellite extensions have posed significant drilling challenges. The complex 3D well trajectories require precise steering control to optimally position the wellbore within the reservoir. Ability to reach the reservoir targets has
been challenged by high levels of downhole shock and vibration and torque limitations of certain drillstring components. In earlier wells, the levels of shock and vibration encountered while drilling in both the intermediate and production hole sections
resulted in issues including low rates of penetration, premature bit wear, damaged tools and unplanned trips for downhole tool failures.
A number of issues contributed to drilling challenges, including weather, ice encroachment, and rig equipment challenges. Extensive drilling and completion design and operational improvements were achieved over a period of 3 years from 2009 to 2012. These improvements included changes to, well trajectory designs, drillstring and bottom hole assembly (BHA) designs, procedures for torque-and-drag management, fluids designs, and lower completion design. These combined efforts significantly reduced downhole-related nonproductive time, despite a substantial increase in well complexity.
Macondo is a "game changer?? that will substantially impact the oil and gas industry from an operational, contractual and risk management perspective.
Decisions in the Macondo litigation that is pending in a U.S. District Court in New Orleans will impact operators, drillers, service and supply companies in respect of pollution liability in general and contractual indemnity/release provisions in particular.
This paper primarily reviews and analyzes landmark Court decisions on summary judgment motions regarding interpretation, applicability and enforceability of the indemnification provisions and releases in the drilling and cementing contracts that were applicable to the Macondo well.
In January 2012 rulings on summary judgment motions involving the drilling and cementing contracts, the Court determined that contractual indemnification may apply even in the event of gross negligence or strict liability but will not be applicable to protect a party against intentional wrongdoing as a matter of public policy. The Court also ruled that the scope of indemnification excludes punitive damages as a matter of public policy. The Court held that contractual indemnification may apply to protect an indemnified party from penalties assessed under the Oil Pollution Act of 1990 ("OPA'90??) but not under the Clean Water Act ("CWA??). The Court deferred ruling on whether a material breach of contract would invalidate indemnity protection. In the decision relating to the cementing contract, the Court also ruled that indemnities will be invalidated by fraudulent acts that constitute intentional wrongdoing and deferred ruling on whether penalties or fines under the Outer Continental Shelf Act ("OCSLA??) are subject to contractual indemnity.
This paper reviews these rulings in detail and includes the author's commentary on the decisions and the interpretation (or, perhaps more accurately, misinterpretation) of certain of the drilling contract provisions based upon over 35 years of drilling industry experience primarily as an executive overseeing legal, contracts and risk management activities.
The Court rulings in the Macondo litigation will have a profound impact upon the offshore industry, especially with respect to contract terms, risk management and insurance. While U.S.-centric and primarily applicable to U.S. maritime law, the litigation and other ramifications of Macondo are expected to ultimately have considerable global impact both offshore and onshore.