Drilling in high speed applications typically requires the use of a turbine or a uniform-rubber thickness motor. While both generate high rotating speeds, both are limited in the output power transferred to the bit. This decreases the drilling potential of the bit, especially impregnated bits, which are designed to handle high speeds and power, thereby producing excellent Rate of Penetration (ROP) in hard rock drilling. Additionally, the per-foot drilling cost for turbines and uniform-rubber thickness motors is significantly higher when compared to traditional drilling motors and in some cases the cost of turbines prevents the introduction of impregnated bits to certain markets.
A new and unique positive displacement motor has proven that the use of turbines and uniform-rubber thickness motors are not the only choices for high speed drilling. This new motor is similar to conventional positive displacement motors in that it consists of a bearing assembly, drive transmission shaft and power section for speed and power generation. However, the power section is a modified 2:3 lobe configuration with special geometry features which minimize the out of balance forces caused by rotor rotation. These special geometry design features are based on the use of a standard round power section tube, meaning the use of specialty manufactured and expensive uniform-rubber power section tubes are not required. The net result is a 2:3 lobe configuration that can rotate at the speeds required for high speed drilling while generating higher output power than existing technology.
Field testing of this new motor design has shown performance that meets or exceeds existing high speed drilling technology with regards to ROP and total drilling time. Drilling locations that require high Weight on Bit (WOB), which frequently causes problems with other technologies, was not a challenge as the new motor design was able to drill-off after multiple high pressure spikes. The overall motor cost was lower than turbines and uniform-rubber thickness motors, benefitting the operator with a lower cost per foot with equal interval drilled. This unique motor design gives operators a new tool to optimize performance in high speed drilling applications.
Managed Pressure Drilling (MPD) has gained industry-wide acceptance as a technology that enables drilling into the challenging zones. Narrow pore pressure - fracture pressure window, depleted reservoir zones, highly fractured reservoirs and deep-water wells are few examples of such challenges. Weatherford's MPD system has proved its effective application in drilling challenging wells. Its unique early kick and loss detection software capability helps to identify such event in very early stage, take corrective action and hence to minimize the nonproductive time. Early detection of a kick / loss event helps in minimizing the potential risk posed by the event and ensure safety during the operations.
Weatherford's advanced gas extraction and analysis system uses an innovative membrane technology and high speed gas chromatograph to improve surface gas detection and analysis in real time. This capability was utilized in conjunction with accurate flow metering capability of MPD system. Various tests were carried out to validate the advanced gas detection system's capability to detect and analyze gas in mud. During circulation of the influx, data from gas detection system helped to plan the strategy gas on the surface. The test data was validated by the data from real wells.
Feedback from the advanced gas detection system also helped to control the break out of the dissolved gas from oil based mud by varying surface back pressure through automated chokes. This is very critical to ensure that gases containing hydrocarbons are handled safely on the surface. It also provided quantitative analysis of the lighter and hence volatile hydrocarbon components. Circulation rates and surface back pressure can be used to mitigate potential hazards. Use of advanced gas extraction system in combination with MPD system added significant HSE value by making well control operations more efficient and safer.
Environmental impact has become business critical as we have been unable to crack certain issues to the degree expected for our industry. It is the central challenge for the continued development of shale markets, as it has been offshore. In a customer survey completed in the first quarter of 2012, a diverse group of operators, drilling contractors, and service companies identified their top three challenges for shale development: pricing, inexperienced personnel, and—of paramount importance—environmental impact. The industry recognizes the need for reduced environmental impact, but what do we need to achieve it?
In the aforementioned survey, many operators and drilling contractors expressed looking to oilfield service and supply companies for continued innovation with the expectation that they continue to be to be forward-thinking and present ideas that provide value. The industry has two primary means for reducing environmental impact of its operations: processes (operator and contractor-driven) and equipment (service and supply-driven). This paper proposes that the two must work hand-in-hand. It explores the opportunity to take this further: identifying critical steps such as process design for reduced environmental impact with lower-impact technology and industrial engineering. The dual approach is needed to affect large-scale change.
This paper will examine the positive impact of the implementation of select environmental technology can have on oilfield economics from the perspective of an oilfield equipment, technology, and services provider. It aims to:
- Demonstrate a case for environmental solutions
- Establish the importance of improved environmental performance for market access
- Identify areas in which operators evaluate environmental impact
- Discuss the technology opportunities available to operators
- Recognize and quantify the performance and cost benefits of aforementioned technologies.
Bageri, B. S. (King Fahd University of Petr. & Min.) | Al-Majed, A. A. (King Fahd University of Petr. & Min., Dhahran, Saudi Arabia) | Al-Mutairi, S. H. (Saudi Aramco) | Ul-Hamid, A. (King Fahd University of Petr. & Min., Dhahran, Saudi Arabia) | Sultan, A. S. (King Fahd University of Petr. & Min., Dhahran, Saudi Arabia)
Good knowledge of filter cake structure and composition leads to successful selection of drilling fluid that minimizes formations damage and selection of an effective and efficient recipe for removing the filter cake.
This study focus on an aspect which was not fully covered in the literature: the chemical characteristics of filter cake formed along the horizontal well, from its heel to its toe. High pressure fluid loss tests were performed using real drilling fluid
samples from the field which were collected during drilling horizontal section of a sandstone formation. The mineralogy of the external filter cake formed by fluid loss cell is determined using both Scanning Electron Microscopy (SEM) and X-Ray
The results showed that for long horizontal sections, the composition of the filter cake was not constant from its heel to its toe since the small drilled cuttings or particles, that are not completely removed, were mixed with the drilling fluid during
circulation and become an integral part of the fabric of the filter cake.
Gonzalez, Fernando Daniel (Halliburton) | Franco, Roberto (PEMEX) | Rodriguez, Reginaldo (PEMEX) | Franco, Roberto (PEMEX) | Gamez, Gustavo (PEMEX) | Blas, Bernardo (Halliburton) | Vasquez, Jose Luis (Halliburton) | Alcudia, Hugo (Halliburton)
The Jujo-Tecominoacan field belongs to the Bellota Integral Active in the Pemex South Region. It is located in the state of Tabasco, northwest of the city of Villahermosa. This field is geologically located in the Chiapas-Tabasco Mesozoic Basin and is developed to maximize production of fractured carbonate formations from the lower Cretaceous to the Kimmeridgian Jurassic. Several drilling challenges are presented including horizontal drilling in dolomites with a high compressive strength, low pressure and high temperature reservoir requiring the use of a biphasic drilling fluid with nitrogen injection through concentric casing annular space, crossing through Cenozoic members of abnormally high pressure that require managed pressure drilling, drilling through inverse geologic faults, and proximity to a salt dome.
An interdisciplinary team was formed between the service company and operator to meet the challenges of constructing the deepest and longest concentric N2 injection horizontal well in the world with a total depth of 6611 m in a Low Pressure- High Temperature ambient. A horizontal production section was drilled to a length of 862 m and with an average inclination of 84°. The main objective was to maximize production in fractured carbonate formations from the lower Cretaceous to the Kimmeridgian Jurassic formation. Managed pressure drilling was implemented in the 6 ½?? hole section while drilling through the upper Jurassic production zone, allowing establishment of commercial production and incorporation of the oil reserves in these zones.
With 260 days of operation, the Tecominoacan 705 well, is the pioneer example of a combined effort of the operator and service company with the objective accomplished, setting a worldwide standard of unprecedented execution.
As the world's demand for energy continues to grow, exploration and production activity increasingly involves operations in high-pressure, high-temperature (HPHT) conditions. HPHT domains include geothermal, steam-injection, and ultradeep wells. These environments introduce difficult technical challenges. A major concern is the set-cement integrity. To maintain zonal isolation throughout the life of an HPHT well, the cement sheath must perform reliably at temperatures that can exceed 315°C [600°F]. When exposed to temperatures higher than 110°C [230°F], set Portland cement undergoes strength retrogression unless additional silica is incorporated in the cement formulation. This phenomenon has been studied extensively. However, less attention has been paid to the effects of other additives on the stability of set Portland cement in an HPHT environment—weighting materials in particular. Weighting materials have largely been assumed to be inert with respect to set Portland cement; however, the present study reveals that this assumption may be false in HPHT environments in which well temperature exceeds 260°C [500°F]. Some weighting agents may react with the set Portland cement, causing strength loss and increased permeability. Fortunately, this effect can be prevented, and the set-cement integrity can be preserved.
With the ongoing changes affecting the global drilling industry, well integrity has become an area of great engineering focus and development. Cement bond analysis is of key interest as the consequences of failed, or partially complete, cementing
operations can, at best, be a costly delay in drilling operations and, at worst, an extremely hazardous safety issue. Traditionally, wireline acoustic tools have been used to analyze the quality of the cement bond between the casing and the formation. Wireline tools have been developed over many years to produce high-quality assessments of cement bond, which can then be confidently used to confirm well integrity. However, the conveyance method requires that the analysis be performed on the critical path and also that additional methods be used in high-angle wells. Logging-while-drilling (LWD) technology offers a potential alternative without these issues, provided the current limitations of the technology are understood and its applicability properly assessed as a fit-for-purpose solution. As a minimum, the LWD logging technique can provide a trigger as to whether more advanced logging techniques must be deployed or can be avoided.
This paper explores the applicability of LWD sonic tools to the analysis of cement behind casing. It considers both the currently accepted deliverable of top of cement (TOC) analysis, along with examples of more advanced processing techniques and their comparison to wireline cement evaluation, providing case study examples in each case. The benefits and limitations of these methods will be discussed, along with operational considerations to aid in successful logging, including the use of repeat logging passes to indicate changes in cement quality with time. The use of LWD sonic tools to identify casing collar connections on driller's depth, enabling the safe positioning of cased-hole whipstocks, is also covered, demonstrating a novel and little-used application of LWD technology.
1202 PROGRAM ALARM This disturbing alarm, displayed to the men on location and in a remote center during the most critical part of the operation, signaled that the onsite computer system was no longer able to handle its automated multi-tasking requirements. The crew was forced to assume manual control to complete the operation, but not without continued assistance from onsite computers and engineers monitoring the event in the remote center. A short time later came the announcement heard by 600 million people around the world - "Houston, Tranquility Base here. The Eagle has landed.?? Neil Armstrong had safely landed the Apollo 11 Lunar Module on the Moon.
Automation, perhaps the most game-changing opportunity in drilling today, is improving operational safety, efficiency, quality, and economics. More importantly, automation is making possible the execution of operations and activities difficult or even impossible for rig crews to complete using traditional methods. Notable recent success notwithstanding, the uptake of automation could be accelerated by the creation of industry-wide and segment-specific technology roadmaps to define short- and long-term goals and track progress. While most technology roadmaps are extensive and detailed documents, they must be built on a solid foundation that represents an overall view of the technology. Presented in this paper is a new design aid developed precisely for creating and displaying this view. For drilling automation in general and any number of specific operations and supporting technologies, the design tool can visually illustrate current and future (desired) states and the path(s) connecting the two. This visual approach also serves to catalyze discussion of this important topic.
The design tool presented here is a radically different way to create a technology roadmap overview. It is based on the common ternary chart, a triangular diagram that graphically depicts the composition of three-component systems. For drilling automation, the three components are rig equipment automation, rigsite manpower, and engagement from remote operation centers. Proportions of the three variables total 100% by definition. Simply stated, this means that a reduction of personnel on board, for example, must be balanced by increased automation of rig equipment and/or a higher level of engagement from remote operation centers.
The primary objective of this paper is to describe the underlying technology of this drilling-system automation design aid and to demonstrate how it can be used for real-world applications. There is no intent to present hard data that could be used directly to generate automation roadmaps for drilling.
Gupta, Vishwas P. (ExxonMobil Development Company) | Sanford, Shea R. (ExxonMobil Development Company) | Mathis, Randall S. (Exxon Neftegas Limited) | DiPippo, Erin K. (Exxon Neftegas Limited) | Egan, Michael J. (AIPC, Consultant to Exxon Neftegas Limited)
ExxonMobil, as operator for the Sakhalin-1 project, recently planned a drilling campaign at the Chayvo Field, Sakhalin Island, Russia. The focus of this campaign is the development of a thin oil column reservoir using extended reach drilling (ERD). This paper will provide an overview of the planning of these challenging wells at the edge of the ERD envelope, the associated technical and operational challenges, and the additional complexity of targeting a thin oil column in an ERD environment. Significant well design parameters, tools, and techniques to enable these challenging wells will be presented. Results to date from this drilling campaign will also be presented.
ERD has become a commonly used technique to economically access reserves from existing infrastructure and to reduce the facilities environmental footprint. The case history described in this paper illustrates the combination of planning, technical design, and operational practices required to push the ERD envelope further.
The distance of the reservoir from shore resulted in planned well lengths at the edge of the ERD envelope. Planning of these record wells involved building upon the Operator's previous experience as well as additional tools and methods to address the unique challenges. The technical challenges included uncertainties in the location of the oil column and fluid contacts, very accurate well placement for effective reservoir drainage and preventing early gas/water breakthrough, completing long horizontal intervals, and high torque and drag. The geologic uncertainties and wellbore positioning challenges were addressed using a combination of a single near horizontal pilot hole to locate both fluid contacts and a novel technique to minimize vertical position uncertainty using formation pressure measurements while drilling. Extensive torque and drag and wellbore stability modeling were performed to design the wells, operational parameters, and equipment. Completion designs were optimized to ensure successful placement in long horizontal intervals.
Liner hangers are designed to provide seal and anchoring capability for installation of casing. The expandable liner hanger has a uniform body with no moving parts that will expand into the parent casing and provide a permanent and reliable seal.
Unfortunately, drilling a well can be problematic in certain situations, resulting in loss of a section or the entire wellbore. This leads to additional well construction costs from milling casing, running a sidetrack, or drilling a new section. Retrieving sections of the installed casing can reduce the cost but may require removal of the liner hanger. While milling conventional hanger systems has been performed before, there has been little experience with milling an expandable liner hanger.
This paper discusses the first two cases in the North Sea where expandable liner hangers required milling because of drilling issues below the liners. The milling of the expandable hanger bodies provided several benefits when compared to the milling of conventional liner hanger systems. The benefits included reduced rig time and non-productive time (NPT), less well debris than when milling movable parts/slips, and no parent-casing slip damage.
In the first case, during running of an expandable liner hanger, the hanger disconnected and was lost. A backup hanger was run, cemented, and set. Options for correcting the situation will be discussed in this paper along with why milling was considered the most feasible option. In the actual job, 10.5 feet of hanger were milled out in less time than anticipated. In the second case, a liner and expandable hanger were set in a long, extended mature reservoir.
During drilling of the next section, the drill string became stuck, requiring a sidetrack. Milling of the expandable liner hanger system enabled the operator to pull the liner and perform the needed sidetrack.