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Deepwater drilling needs improved efficincy. Since well delivery cost is a major component of deepwater projects, a 20% reduction in well delivery cost may pull deepwater projects back over the economic threshold. However, sustainability requires looking beyond market cycle price consessions and focus on longer term technology and innovation to drive down the well duration and cost. Accordingly, the industry needs to apply engineered soultions to increase operational efficiency and safety as compared to existing 6th Gen drillship designs.
This paper introduces a next generation drillship design concept, featuring a factory-like approach to well construction, grounded with input from operators and third-party service providers. Capitalizing on Lean methodologies, the design combines improved safety with automation and robotics to reduce bottlenecks and minimize controllable flat time for the entire well life cycle with a reduction in well duration and cost by 15 to 30%.
The author examines the distinctive vessel layout including a large flat and un-obstructed work deck, a high variable load capacity of 27,500 short ton (ST), and increased personnel on board capacity to improve the off-line transition from the drilling to completion phases. In addition, the reorganized drill floor replaces the standard derrick and substructure with a Dual Multi-purpose Tower (DMPT), employing robotic pipe manipulators capable of handling 180-ft stands. To meet future well design requirements, the hoisting system is engineered for at least a 1,500 ST static hook load at the elevators. Further, independent mud and brine systems with 11,000-bbl and 17,000-bbl capacities, respectively, with off-line tank and suction line cleaning, improve well displacement safety and efficiency. Moreover, a unique power distribution network improves both thruster availability and also allows maintenance while operating efficiently in an open buss configuration, thereby stretching the dynamic positioning (DP) operating envelope.
The target of this efficiency and safety-centric initiative is to reduce the operator's well cost and allowing future optimization of 40,000-ft-plus well designs in 13,200-ft water depth.
Human Factors encompass elements which influence our behaviour. In a work environment they embrace many areas, for example; environmental and organisational, the design and functionality of equipment, process and procedures, individual characteristics of personnel, their skills and competencies.
It is generally acknowledged many of the world's worst oil field incidents have been attributable to Human Factors including well control events like the Montara and Macondo blow outs and many others. It is notable that some well control incidents initially appear straightforward but are frequently exacerbated by human error, increasing risk and costs, and in the worst cases resulting in blowouts.
The oil field has been a little late in realising the importance of Human Factors but there is now recognition they are essential in successfully resolving well control events. The inclusion of Human Factors in managing well control events was also a recommendation of the OGP 476 report in 2012.
The corporate well control manual was refreshed to include Human Factors in the management of well control incidents. This required mapping the well control process, assigning personnel specific roles, defining contingencies, etc. whilst acknowledging the effect Human Factors has on the personnel involved. The intention was not to create a rigid structure but to rather provide a framework to guide the front line in dealing with a well control event. New policies and procedures were subsequently developed and included in the update.
It is recognised this new philosophy will require an ongoing commitment impacting well control procedures, client liaison, bridging documents, the assessment and assurance of teams, well control training etc. It is further acknowledged this is just a first step and there will be continued development and refinement of the management tools as the system beds in.
A reliable interpretation of Fracture Initiation Pressure (FIP) provides key information for both efficient well planning and construction. With the trend towards drilling ever deeper offshore wells, depleted zones and more complex well paths, the available mud weight window continues to tighten, so an improved knowledge of the FIP becomes essential in enabling robust designs and risk reduction strategies that together promote safe and efficient operations.
A number of methods are currently used across the Industry to estimate FIP values for drilling and completion applications. These methods involve the direct interpretation of data from injection tests, such as Diagnostic Fracture Injection Tests (DFIT), Formation Pressure Integrity Tests (FPIT) or even Wireline Formation Tests (WFT). In this paper, the authors propose and present a simplistic yet effective approach to derive values for the FIP from such typical pumping test data. The method is based on long established principles linking the pressure, volume and in-situ rock properties of the system being tested.
This paper provides a number of examples to demonstrate the application and validity of the approach, including the consideration of scaled laboratory block tests, through to actual field data. The relationship between FIP, FBP and closure pressure is presented and discussed for all of these cases. The method is based on early-time wellbore stiffness considerations and as such complements and augments the more conventional fracture closure analysis approach from decline data. Using this technique, additional valuable information may be extracted even from only partially completed tests, where formation breakdown analysis by conventional means may either be impossible to perform or at best is somewhat inconclusive.
In summary, while there are many and varied techniques that have been widely developed in support of obtaining FIP, the quality, the repeatability and assurance of these approaches is often incomplete and can sometimes be misleading. The simplistic methodology that is outlined and presented here provides a complementary approach, with the potential to offer a more consistent estimation of this key pressure control parameter. The method also provides the possibility of identifying the FIP in those situations where the currently available data (quantity and/or quality) would suggest that conventional methods might well fail to deliver an unbiased interpretation.
In the past two decades, the point-the-bit rotary steerable system (RSS) has been widely used for high-profile directional drilling jobs in challenging environments, which require accurate directional control. A new inertial steering mode of the point-the-bit RSS was developed by using accelerometers and a rate gyroscope sensor to achieve toolface control in environments, where magnetometers cannot be used for steering. This inertial steering mode effectively expands the operational envelope of point-the-bit RSS by improving its steering ability when magnetic interference, such as drilling out of whipstock window and close to offset wells or ferrous formations, is present or within a Zone of Exclusion (ZOE). Furthermore, the new steering mode can be used as a redundancy scheme in circumstance during magnetometer failures.
Through close collaboration between Research and Development (R&D) and field operation, the inertial steering mode of the point-the-bit RSS has been successfully applied in four wells in Middle East oilfield. In the first well, the new steering mode was used to kick off two 8 3/8" hole sections after setting whipstocks in near vertical wells and it completed the kick-offs in desired directions with accurate toolface control in a high magnetic noise environment. In the second well, the new steering mode was used to exit the casing and drill to TD by using a whipstock. In the third and fourth wells, 12 ¼" hole sections passing through the ZOE were successfully drilled according to the well plan. The application of the new steering mode in these wells saved extra BHA trips, which would have been required if without this new steering mode.
The successful application of the new steering mode in the Middle East oilfield has proven its technical advantages and business benefits.
This paper presents and discusses the results of the field application where a new integrated expandable under reamer technology was implemented in the North Sea. An operator faced issues with wellbore stability and equivalent circulating density (ECD) while drilling a 12¼-in. section in a challanging formation. Placing the reamer close to the bit removed the need for an additional rathole elimination run, avoiding the risks associated with it and saving rig time.
The on-command digital, expandable under reamer is fully integrated into the bottom hole assembly (BHA) and can be monitored and controlled from the surface. The under reamer tool has unlimited activation cycles that provide the capability of selective reaming. The flexible placement of multiple reamers in the BHA enables near-bit and main reaming applications, and a combination of both. When used for near-bit reaming service, the reamer can reduce the rat-hole length to 4 m. Significant time savings and safety improvements can be achieved by simultaneously operating the main and the near-bit reamer.
In one run, the entire section was simultaneously drilled and underreamed to TD. The first 3,491 ft (1064m) were drilled while simultaneously opening the hole to 13½-in. with the main underreamer. The remaining 233 ft (71m) were drilled and reamed with both the main and the near-bit reamers activated. The rathole length was reduced to 33 ft (10m) in the same drilling run, saving 3 days of rig time. The 10¾-in. liner was then run to the desired depth. Minimal vibrations were recorded in the interval where both reamers were activated and stick/slip was nominal. After the run, an inspection of the reamer blades showed good performance and little wear.
The paper will summarize and describe the results and features in detail, and demonstrate how they can help the operators to reduce operational risks and save cost.
Yu, B. (Baker Hughes) | Goodman, A. (Baker Hughes) | Hayes, B. (Baker Hughes) | Stevens, J. (Baker Hughes) | Vondenstein, T. (Baker Hughes) | Callais, R. (Baker Hughes) | Harvey, J. (Antero Resources) | Honeycutt, J. (Antero Resources) | McEvers, J. (Antero Resources) | Lindsey, J. (Talos Energy)
Bit balling and balling on other bottom hole assembly (BHA) components is a common concern when drilling shale with water-based mud (WBM) because it limits drilling efficiency or in extreme cases can stop drilling, causing costly non-productive time (NPT).
Among many strategies which have been created to mitigate the above balling problem, an effective approach is coating the tool surfaces with hydrophobic materials that are generally characterized by high water contact angle. This approach has been pursued by bit manufacturers with some success; however, poor coating durability is still a common concern. Additionally, previous applications are often guided by surface hydrophobicity evaluated at ambient conditions. Elevated temperatures and wellbore pressures can potentially cause the behavior to change and limit effectiveness. Therefore, evaluating the surface hydrophobicity under conditions that closely simulate downhole conditions becomes essential.
To address these challenges, this paper reports the recent success on a new anti-balling coating technology and the novel high-pressure, high-temperature (HPHT) laboratory tests used to develop it. The laboratory-level HPHT apparatus developed in this study is capable of measuring key parameters including the contact angle and interfacial tension at extreme conditions of up to 500 °F and 30,000 psi. It is also demonstrated how pressure and temperature have an impact on the surface hydrophobicity.
The newly developed coating technology combines good surface hydrophobicity at HPHT conditions with superior wear performance. The development results were later demonstrated in several shale applications (Marcellus Shale, West Virginia in 2014; East Cameron, Gulf of Mexico in 2015), where the coating technology was applied onto 8 ½" diamond bits that at one time drilled up to 10,000 ft in a single run without requiring a trip while still maintaining coating functionality.
This development work provides drilling operations with an effective solution to improve the performance in balling-prone shale applications. Additionally, the body of work demonstrates the importance of material testing in conditions matching real-world applications and how this approach leads to improved material selection for solving downhole problems.
Unintentional collision between two wellbores may have serious economic and health-safety-environmental (HSE) consequences. It is therefore important to evaluate the probability of such an event in the well planning phase, and at critical stages during the drilling phase.
A commonly used approach is to analyze the collision probability between two points, one in each wellbore, that are determined from geometric criteria only. This procedure may ignore point pairs with higher collision probabilities, and thereby lead to over-optimistic conclusions. Typically, the results from such methods will be accurate only for simple wellbore geometries such as straight sections and for position uncertainties that are highly symmetrical with respect to the wellbores. More advanced methods that overcome such limitations are impractical for general application because of high conceptual or computational complexity.
This paper proposes novel analytic methods that potentially may overcome these problems. Formulae are derived for two important situations: the direct hit and the unintentional crossing scenarios. In both cases, the spatial region of interest is divided into carefully designed segments, such that the collision probability can be accurately evaluated for each segment. The total collision probability is then found by summing the results over all segments. The main advantage of this approach is that it gives accurate results for arbitrary well geometries and uncertainty ellipsoid orientations.
The algorithms can easily be integrated in existing software for wellbore anti-collision analysis. The paper shows examples of results, which all are in good agreement with control calculations. Compared to existing methods, the proposed methods are therefore believed to represent a significant improvement to quantitative collision probability analysis, for both the wellbore planning and the drilling phases.
Engelke, B. (Schlumberger) | de Miranda, C. R. (Petrobras) | Daou, F. (Schlumberger) | Petersen, D. (Schlumberger) | Aponte, S. A. (Schlumberger) | Oliveira, F. (Schlumberger) | Ocando, L. M. Sarcos (Schlumberger) | Conceição, A. C. F. (Petrobras) | Guillot, D. (Schlumberger)
In a joint effort, an oil and gas operator and a service company have undertaken research to help overcome well integrity and cementing fluids challenges in the presalt wells of Brazil where some fields present high levels of CO2 in reservoir fluids. Results are provided from the laboratory phase to cement placement evaluation.
The new approach is to provide a cementing system that is not only resistant to CO2 attack but also has a self-healing capability in the presence of fluids containing CO2. The validation of the CO2 selfhealing and resistant cement technology was initiated at laboratory level. Then, a yard test with real-time field parameters was performed, proving that the new slurry can be mixed and pumped using conventional cementing equipment. Finally, an onshore well in Brazil served as a test well for deploying and evaluating the new CO2 self-healing and resistant cement system in the field.
The technology consists of an engineered particle size distribution (EPSD) blend containing a reactive material that swells upon contact with CO2. This swelling allows the closure of microfissures and/or the reduction of the microannulus, which heals the cement sheath and reestablishes the integrity of the well. Then, a large-scale yard test was performed to evaluate real-time field parameters such as the fluidity and homogeneity of the dry blend and the mixability of the slurry using conventional cementing equipment. After the success of the yard test, the technology was deployed in Brazil. During the field test, 8 m3 [50 bbl] of 1,900 kg/m3 [15.8 lbm/gal] CO2 self-healing cement was pumped downhole and placed in the annular space between a 7-in. casing and a 8.5-in. open hole to promote casing support and zonal isolation in the production zone.
The CO2 self-healing and resistant cement overcomes the deficiencies of conventional Portland cement in carbon dioxide environments and presents an advantage over other available technologies designed to withstand CO2 attack by maintaining zonal isolation and long-term well integrity. Moreover, this technology can be applied in any field in the world where CO2 is regulated and/or entails risk for operators or the general public.
Extensive set of experimental setups have been designed and build to evaluate the sealing performance of systems for zonal isolation and well abandonment. The fully automated test procedure enables the comparison of systems under identical conditions (P, T). Additionally a novel setup has been built to concurrently measure the internal and external volumetric change during the hydration reaction of cement systems at well conditions.