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Stefánsson, Ari (HS Orka) | Duerholt, Ralf (Baker Hughes, a GE company) | Schroder, Jon (Baker Hughes, a GE company) | Macpherson, John (Baker Hughes, a GE company) | Hohl, Carsten (Baker Hughes, a GE company) | Kruspe, Thomas (Baker Hughes, a GE company) | Eriksen, Tor-Jan (Baker Hughes, a GE company)
The typical rating for downhole measurement-while-drilling equipment for oil and gas drilling is between 150°C and 175°C. There are currently few available drilling systems rated for operation at temperatures above 200°C. This paper describes the development, testing and field deployment of a drilling system comprised of drill bits, positive displacement motors and drilling fluids capable of drilling at operating temperatures up to 300°C. It also describes the development and testing of a 300°C capable measurement-while-drilling platform.
The development of 300°C technologies for geothermal drilling also extends tool capabilities, longevity and reliability at lower oilfield temperatures. New technologies developed in this project include 300°C drill bits, metal-to-metal motors, and drilling fluid, and an advanced hybrid electronics and downhole cooling system for a measurement-while-drilling platform. The overall approach was to remove elastomers from the drilling system and to provide a robust "drilling-ready" downhole cooling system for electronics. The project included laboratory testing, field testing and full field deployment of the drilling system. The US Department of Energy Geothermal Technologies Office partially funded the project.
The use of a sub-optimal drilling system due to the limited availability of very high temperature technology can result in unnecessarily high overall wellbore construction costs. It can lead to short runs, downhole tool failures and poor drilling rates. The paper presents results from the testing and deployment of the 300°C drilling system. It describes successful laboratory testing of individual bottom-hole-assembly components, and full-scale integration tests on an in-house research rig. The paper also describes the successful deployment of the 300°C drilling system in the exploratory geothermal well IDDP-2 as part of the Iceland Deep Drilling Project. The well reached a measured depth of 4659m, by far the deepest in Iceland. The paper includes drilling performance data and the results of post-run analysis of bits and motors used in this well, which confirm the encouraging results obtained during laboratory tests. The paper also discusses testing and performance of the 300°C rated measurement-while-drilling components – hybrid electronics, power and telemetry - and the performance of the drilling tolerant cooling system.
This is the industry's first 300°C capable drilling system, comprising metal-to-metal motors, drill bits, drilling fluid and accompanying measurement-while-drilling system. These new technologies provide opportunities for drilling oil and gas wells in previously undrillable ultra-high temperature environments.
Improved characterization of formation fluids in downhole sampling tools is an industry development goal. In-situ viscosity (η) and fluid density (ρ) measurements are important to improve estimates of formation permeability, to monitor downhole sample cleanup, and analyze downhole fluid compositions such as gas/oil ratio. Dynamic viscosity in combination with other fluid parameters such as fluid density, sound speed, refractive index, absorption spectroscopy and thermal conductivity can provide a comprehensive characterization of the sample fluid. Estimating the formation permeability is critical for predicting the reservoir’s production potential. Mobility measurements performed on the formation using various downhole sampling tools can be used to calculate the permeability of the formation when accurate in-situ viscosity of the formation fluids is known.
Sample fluid varies during cleanup from mud-filtrate at the start of the drawdown process via filtrate-contaminated formation fluid toward the final clean formation sample. The sample fluid may be any combination of various molecular weight hydrocarbons, brine, oil- or water-based mud filtrate and gases. The fluids also can be conductive, and they can have partially non-Newtonian properties and a viscosity typically in the range of 0.5 to 4 cP (mPa*s) or even up to 40 cP in heavy oils. Fluid density can range from 0.2 up to 1.5 g/cc.
A sensor applicable in a downhole formation sample and analysis tool must fulfill the demanding requirements of the measurement task with the huge dynamic range and an accuracy of better than 10%. The sensor must also be capable of measuring in temperatures up to 175°C and pressures exceeding 25 kpsi.
This paper presents a new sensor that can manage all the aforementioned requirements. Using the concept of a mechanical oscillator that is interrogated for resonance-frequency and damping, a sensor was designed that is highly accurate and provides sufficient robustness against temperature, pressure and drilling vibrations. The accuracy for measuring viscosity is 0.1 cP for fluids less than 1 cP and 10% for all viscosities outside the range. The density accuracy is better than 0.01 g/cc. The sensor is applicable for wireline and logging-while-drilling (LWD) tools.
This paper also presents the high-temperature and high-pressure qualification tests. Results of viscosity and fluid density lab measurements conducted with the new sensor are shown using a variety of calibration fluids that represent downhole fluids as they appear in a formation sampling tool.
Kruspe, Thomas (Baker Hughes, Inc.) | Thern, Holger F. (Baker Hughes, Inc.) | Kurz, Gerhard (Baker Hughes, Inc.) | Blanz, Martin (Baker Hughes, Inc.) | Akkurt, Ridvan (Saudi Aramco) | Ruwaili, Saleh (Saudi Aramco) | Seifert, Douglas (Saudi Aramco) | Marsala, Alberto F. (Saudi Aramco)
Magnetic Resonance (MR) Logging While Drilling (LWD) has gained widespread acceptance as a nuclear source-free and lithology-independent porosity measurement for hole sizes above 8½ inch. The importance of slimhole measurements is increasing today because deeper and more complex reservoirs are being drilled. Comprehensive formation evaluation requires a full suite of LWD tools including a 4¾-in. slimhole MR-LWD—a tool size which was considered impossible for a long time. Formation evaluation (FE) in slimhole applications is challenging for several reasons. Downhole drilling dynamics is known to be more severe because drillstring stiffness and weight are reduced. Furthermore, the presence of a smaller cross-sectional area for the tools limits the space available for sensors and electronics.
After validating the feasibility of a slimhole MR-LWD tool by solving these fundamental design problems, it has now become possible to offer this service in borehole sizes ranging from 5⅞ to 6⅛ in. Using the latest magnet technology and optimizing the measurement for a smaller hole size have lead to highquality MR data with good signal-to-noise ratio. Combined with a real-time T2 distribution, the tool provides an MR-LWD service ready for everyday petrophysics, simplifying and enhancing integrated FE data interpretation tremendously. The slimhole MR-LWD service has been deployed in applications ranging from standard porosity measurements to complex tasks such as hydrocarbon typing and heavy oil/tar detection. Several case histories provided illustrate the value added by the availability of a slimhole MR-LWD tool in solving challenging petrophysical problems.
Today’s increased interest in managing fossil fuel reserves calls for opening up new opportunities. Service companies are required, therefore, to push the limits of available technologies for improved identification and characterization of reservoirs. It is critical to remain application-focused to fulfill oil companies’ requirements and to deliver a high-quality product in an acceptable time frame. We describe the successful development of a 4¾-in. MR-LWD tool by tying pioneering technology developments to highly valuable oil field applications.
MR is often used in the context of porosity tools such as Density and Neutron. The value of MR data, however, surpasses widely that of a conventional porosity device. The relaxation time T1 and T2 distributions provided by MR measurements reflect a variety of both rock and fluid properties.
• Bound vs. movable fluids
• Capillary-bound vs. clay-bound water
• Rock quality
• Facies variations
• Type of fluid (gas, oil, water)
• Hydrogen Index H.I.
• Fluid composition incl. gas-oil-ratio GOR
• Viscosity MR while drilling was introduced and deployed during the past 10 years.
With a tool size of 6¾ in. MR-LWD data were available for 8⅜- to 10⅝-in. borehole sizes (Prammer et al. 2000a; Horkowitz et al. 2002; Borghi et al. 2005).
Akkurt, Ridvan (Saudi Aramco) | Marsala, Alberto F. (Saudi Aramco) | Seifert, Douglas (Saudi Aramco) | Al-Harbi, Ahmed (Saudi Aramco) | Buenrostro, Carlos (Saudi Aramco) | Kruspe, Thomas (Baker Hughes) | Thern, Holger F. (Baker Hughes) | Kurz, Gerhard (Baker Hughes) | Blanz, Martin (Baker Hughes) | Kroken, Asbjorn (Baker Hughes)
Copyright 2009, Society of Petroleum Engineers This paper was prepared for presentation at the 2009 SPE Saudi Arabia Section Technical Symposium and Exhibition held in AlKhobar, Saudi Arabia, 09-11 May 2009. Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and whom the paper was presented. Abstract Nuclear Magnetic Resonance (NMR) was identified as a critical technology for reducing uncertainty and minimizing risk during the planning phase of a major field development project. The reservoirs in the subject field contain heavy oil/tar in the flanks, and accurate knowledge of viscosity trends becomes essential for the placement of water injectors. Since NMR logs can be used to estimate heavy oil viscosity, the development plan required running logging while drilling (LWD) NMR logs in the extended-reach horizontal injectors, in addition to some selected producers. The first two prototypes were delivered for field testing in less than 18 months. The prototypes have been run in nearly a dozen wells to date and in a variety of environments, including extended-reach wells with high salinity muds. Data obtained from drilling and reaming runs agree very well with those from other porosity tools, including wireline NMR.
Akkurt, Ridvan (Saudi Aramco) | Seifert, Douglas (Saudi Aramco) | Al-Harbi, Ahmed (Saudi Aramco) | Al-Beaiji, Talal M. (Saudi Aramco) | Kruspe, Thomas (Baker Hughes Inteq) | Thern, Holger (Baker Hughes Inteq) | Kroken, Asbjorn (Baker Hughes Inteq)
Akkurt, Ridvan (Saudi Aramco) | Seifert, Douglas L. (Saudi Aramco) | Al-Harbi, Ahmed (Saudi Aramco) | Al-Beaiji, Talal M. (Saudi Aramco) | Kruspe, Thomas (Baker-Inteq) | Thern, Holger (Baker-Inteq) | Kroken, Asbjorn (Baker-Inteq)
The economic recovery of hydrocarbons from deepwater reservoirs continues to be a major challenge facing the exploration and production industry, not just contending with the multitude of market uncertainties, but also, more importantly, reservoir deliverability uncertainties associated with deeply deposited pay targets. One large field subject of this study is such, deposited in stacked Pliocene sandstones. These are high net-to-gross, with predominant very fine-grained sands. The efficient sweep of the oil in place requires a detailed understanding of the network of the reservoir pore structure, and the permeability distribution and capillary bound fluids.
To better understand and characterize the permeability and to help quantify the potential reserves, a novel low gradient magnetic resonance LWD tool for application on conventional drilling assemblies was used. This is a major departure from the more conventional techniques which use high gradient magnetic resonance on post-drilled wireline platforms. Advantages of an LWD approach are twofold; the wellbore is in good condition at the time of drilling, yielding high quality data, and the gain in rig time is significant.
The high quality magnetic resonance dataset acquired was confirmed by overlaying with stationary measurements. The data was integrated with offset core data to normalize permeability models and saturation functions. LWD density images acquired during drilling were also used to provide detailed visualizations of the internal laminations of the turbidites, as well as a reservoir structural setting. Formation pressures and mobility measurements acquired during drilling were also integrated in the normalization process to characterize the deliverability of the sands.
The resulting permeability model was used to study and redesign future development in the field. The saturation results also provide an improvement over the previous resistivity-only based saturation values, which were pessimistic due to the fine-grained structure of the reservoir sands.
Magnetic resonance (MR) logging was originally intended for measuring fluid filled porosity, and for differentiating between producible and non producible fluids. Early tools however came with special operational requirements. Wireline logs were slow and sensitive to wash-outs; early logging while drilling (LWD) measurements did not tolerate tool vibrations. Both required a good deal of preplanning to accommodate limited capability hardware. The paper shows how problems of the past could be solved by the innovative technology of Magnetic Resonance Logging While Drilling (MR-LWD).
By returning to basics a new LWD magnetic resonance tool tolerant to vibration and easy to apply could be designed. The novel device acquires valuable data which can be used as well for formation evaluation as for geo-steering under normal drilling conditions and with standard operating practices. This was made possible by a short inter-echo spacing, by a special stabilization, and by a low magnetic field gradient. The new sensor operates with a minimum of preplanning and requires little to no interference with the drilling process.
We present an application of the new system in a European onshore well. In the case described we show how reliable deliverables such as porosity and pore-size distribution can be determined from MR-LWD. Formation boundaries and fluid contact can easily be determined. The clear logs and the intuitive presentation of data makes MR while drilling ready for everyday petrophysics.