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Collaborating Authors
Drilling fluid management & disposal
Summary In the placement process of the cement slurry, treatment fluids such as the spacer are pumped ahead of the cementitious slurry to minimize the contamination of the slurry by drilling fluid and ensure superior bonding to the casing and formation. The spacer discussed in this work can harden with time and act as a settable spacer. This characteristic can be an advantage for well integrity if some spacer pockets are left in the annulus. Rheological compatibility of different mixtures of the spacer with oil-based drilling fluid (OBDF) has been studied using a rheometer, and the resulting R-factor, which indicates the degree of compatibility between fluids, has been calculated. An increase in the flow curve was observed for the mixture of the fluids. However, based on the R-index, these fluids are compatible with displacement in the wellbore. A nonionic surfactant, typically used in conventional spacers acting as an emulsifier and a water-wetting agent, was used in the hardening spacer design. The results show that the addition of OBDF to hardening spacer containing surfactant can increase viscoelasticity. Hardening spacer containing surfactant can successfully reverse the OBDF emulsion. By performing a small-scale mud displacement experiment, we observed that surfactant can improve the wall cleaning efficiency of the spacer while having minimal impact on the bulk displacement.
- Europe (1.00)
- North America > United States > California (0.28)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
Pipe Viscometer for Continuous Viscosity and Density Measurement of Oil Well Barrier Materials
Lima, V. N. (NORCE Norwegian Research Centre AS) | Randeberg, E. (Pontificia Universidade Catolica do Rio de Janeiro (PUC-Rio)) | Taheri, A. (NORCE Norwegian Research Centre AS (Corresponding author)) | Skadsem, H. J. (NORCE Norwegian Research Centre AS)
University of Stavanger Summary The barrier material is a crucial component for wells, as it provides mechanical support to the casing and prevents the uncontrolled flow of formation fluids, ensuring zonal isolation. One of the essential prerequisites for the success of cementing an oil and gas well is the efficient removal of in-situ fluids and their adequate replacement by the barrier material. The quality of the mud displacement is affected by both the density and the viscosity hierarchy among subsequent fluids. Consequently, accurate and reliable measurement of fluid properties can help ensure consistent large-scale mixing of cementing fluids and verification that the properties of the mixed fluid are according to plan. In this paper, we investigate the implementation of a pipe viscometer for future automated measurements of density and viscosity of materials for zonal isolation and perform a sequential validation of the viscometer that starts with small-scale batch mixing and characterization of particle-free calibration liquids, followed by conventional Class G cement and selected new barrier materials. Finally, a larger-scale validation of the pipe viscometer was performed by integrating it into a yard-scale batch mixer for inline characterization of expanding Class G oilwell cement mixing. In all cases, flow curves derived from pipe viscosity measurements were compared with offline measurements using a rheometer and a conventional oilfield viscometer. After a series of measurements and comparisons, the investigated inline measurement system proved adequate for viscosity estimation. The flow curve of the barrier materials showed results similar to measurements using a conventional viscometer, validating the proposed test configuration to continuously measure the rheological behavior of the barrier material. The pipe viscometer flow curves are generally found to be in good quantitative agreement with independent viscometer characterization of the fluids, although some of the pipe viscometer measurements likely exhibited entrance length effects. Future improvements to the pipe viscometer design involve the assessment of even longer pipe sections to allow full flow development at the highest shear rate range and possibly different pipe diameters to improve the measurement resolution of low-shear rate viscosity. Introduction The oil well cementing process involves placing cement slurries in the annular space between the casing and the rock formation. After placement, the cement hardens to form a hydraulic seal in the wellbore, preventing the migration of formation fluids into the annulus. In the placement process, the cement paste flows through the interior of the casing into the annular space that is to be cemented, displacing in-situ fluids as it is pumped toward the surface.
- North America > United States > Texas (0.93)
- Europe > Norway > Rogaland > Stavanger (0.24)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- (7 more...)
PUC-Rio Summary The success of an oilwell drilling operation is directly associated with the correct formulation of drilling fluids and their rheological measurements. The goal of this study is to investigate the usage of a Fann 35A viscometer and the methodology for rheological characterization of drilling fluids by comparison with the use of a rotational rheometer. Flow curves and gel strength tests were performed considering classic measurement artifacts such as apparent wall slip, secondary flows, steady-state (SS) regime, and inertial effects, among others. In addition, a study of the relationship between pressure drop and flow rate in a tube and in an annular space was carried out to investigate the influence of the viscosity function and of the rheological properties on the design of pipelines and the correct sizing of pumps. Use of American Petroleum Institute (API) equations and curve fitting were explored as potential choices for viscosity functions. The results indicate that the use of API equation predictions can compromise the effectiveness of the drilling process, while the choice of an adequate viscosity function is essential for the correct sizing of pumps. The gel strength was evaluated in the viscometer and presented divergent results from those obtained in the rheometer. Furthermore, a grooved geometry was developed for the viscometer to avoid the effects of apparent slip at low shear rates. Some recommendations are made based on the results obtained, which lead to better accuracy in the rheological results of drilling fluids and, consequently, better performance of some functions assigned to it. The proposed improvements and methodologies proved to be promising, although in some cases the cost-benefit remained unchanged. Introduction The main functions of a drilling fluid are cleaning the hole, carrying the cuttings to the surface, and maintaining the downhole hydrostatic pressure and stability of the wellbore. To accomplish these functions, rheological properties, density, lubricity, and pH need to be measured and controlled in the field (Bourgoyne et al. 1986). However, these fluids present complex non-Newtonian behavior, so obtaining their rheological properties is not a trivial task.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
Zonal Isolation Material for Low-Temperature Shallow-Depth Application: Evaluation of Early Properties Development
Agista, Madhan Nur (University of Stavanger (Corresponding author)) | Khalifeh, Mahmoud (University of Stavanger) | Saasen, Arild (University of Stavanger) | Yogarajah, Elakneswaran (Hokkaido University)
Summary Shallow-depth cementing presents unique challenges due to its low temperature and low pore pressure characteristic. The curing process of the cementitious material is typically prolonged at low temperatures resulting in a delayed curing process. The use of a low-density slurry to mitigate low pore pressure introduces another challenge, as it leads to a reduction in the final compressive strength. On the other hand, the operation requires the material to develop enough strength swiftly to be able to efficiently continue the next drilling operation. In addition, the presence of flow zones such as shallow gas and shallow water flow increases the complexity of the cementing process. There have been many developments in cementitious materials for shallow-depth cementing such as rapid-hardening cement and gas tight cement. However, there is little research focusing on the performance evaluation of each material at low-temperature conditions. This paper aims to present a thorough material evaluation for low-temperature shallow-depth cementing. The incorporated materials are American Petroleum Institute (API) Class G cement, rapid-hardening cement, gas tight cement, and geopolymer. Geopolymer is included to evaluate its potential as the green alternative to Portland-based cement. The sets of characterization were conducted during the liquid, gel, and solid phases. The samples were prepared under wide-ranging low temperatures and typical bottomhole pressures for shallow sections. The result shows different performances of each material and its behavior under low temperatures such as prolonged strength development and low reactivity, which necessitates further development of these materials.
- Asia (0.93)
- Europe > United Kingdom (0.46)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Mineral > Silicate (0.69)
- Reservoir Description and Dynamics > Formation Evaluation & Management (0.75)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.35)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
- Well Drilling > Pressure Management > Well control (0.73)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.73)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.73)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Abstract Addressing the challenges of drilling the Cretaceous formations of the Middle Magdalena Valley Basin in Colombia which present a difficult geologic environment characterized by high structural complexity, faulting, and uncertainties regarding operational windows, required the consideration of controlled pressure conditions and the use of two-phase fluid on continuous nitrogen injection. Also, to achieve wellbore displacement enhancing recovery, required a high-angle directional trajectory that involved close directional control and the identification and analysis of operational risks. Therefore, careful planning during the design phase was crucial. This involved identifying a set of engineering practices, mapping operational risks, and offering integrated solutions. Additionally, a thorough analysis of available options and selection of technologies that align with project requirements and challenges was necessary. Furthermore, the incorporation of bottomhole pressure sensors (PWD) was necessary to provide a reliable source of information for personnel in charge of monitoring bottomhole conditions and overseeing nitrogen injection, so that the information collected could be reviewed in real time to determine the effectiveness of the operational parameters implemented and to evaluate unexpected conditions. The results indicated a smooth trajectory with minimal deviations, meeting the directional requirements as modeled by the directional BHA. A limited percentage of detection and data transmission through pulse signals to the surface was deemed acceptable. Additionally, the implementation of automation using service provider proprietary software became feasible. Introduction The main challenges encountered when drilling a naturally fractured limestone reservoirs involves minimizing formation damage resulting from circulation losses. To address this issue, a solution was implemented utilizing Managed Pressure Drilling (MPD) and the injection of Nitrogen as a bi-phasic fluid. The objective of this approach was to generate a controlled Equivalent Circulating Density (ECD) in order to minimize fluid invasion and effectively manage fluid losses. The main difficulty lied in drilling a high angle well in a complex geological environment with significant structural complexities. The operational window was uncertain, necessitating consideration of two-phase fluid conditions and continuous nitrogen injection. Additionally, it was crucial to maintain directional control and meet specific requirements for capturing logging information. To address these challenges, a comprehensive operational risk analysis was conducted, and the appropriate selection of tools and techniques was made to efficiently gather information in harsh conditions. This enabled the reduction of decision-making times and the achievement of operational efficiencies based on real-time data collection.
- South America > Colombia > Tolima Department (0.35)
- South America > Colombia > Santander Department (0.35)
- South America > Colombia > Cesar Department (0.35)
- (4 more...)
- South America > Colombia > Tolima Department > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- South America > Colombia > Tolima Department > Middle Magdalena Basin > Casabe Field (0.99)
- South America > Colombia > Santander Department > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- (11 more...)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Pressure Management > Managed pressure drilling (1.00)
- (8 more...)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212566, “Qualifying Bit Influence on High-Frequency Torsional Oscillations Based on Full-Scale Laboratory Experiments,” by Armin Kueck, Eliah Everhard, and Xu Huang, Baker Hughes, et al. The paper has not been peer reviewed. _ High-frequency torsional oscillations (HFTOs) generate dynamic loads that can damage drilling tools, resulting in cracks, twistoffs, or broken electronics. Recently, a full-scale drilling test rig was proven to generate verified HFTO behavior under laboratory conditions. This rig allows for a comprehensive study of the influences of bit characteristics on HFTO. The complete paper presents methods to qualify bit features to suppress HFTO. Laboratory Rig Setup Test-Rig Design. The full-scale laboratory test rig drills rocks in a pressurized rock chamber. Rate of penetration (ROP), weight on bit (WOB), rotational speed, pressure, bit type, and rock type can be varied. The simulator consists of an open-loop mud-circulation system with capacity for 200 bbl of fluid, two 1,000-hp triplex pumps capable of up to 500 gal/min, a hoisting mechanism for raising and loading the drillstring up to 10,000 lbf, a 1,000-hp rotary drive capable of up to 10,000 ft-lbf, and a pressure vessel rated to 10,000 psi. High-frequency measurement instrumentation, including in-bit vibration sensors, records the tangential accelerations and dynamic torque at various positions in the BHA. The mounted device can be seen in the top left photo in Fig. 1. Measurement. To initially characterize the frequency response of the system, an impact test was performed on the system in a suspended nonoperating state with roving accelerometers (sensors) positioned as indicated by the blue lines in Fig. 1. Also indicated are the free-end and fixed-end boundary conditions at the bit (left) and drive (right), respectively, as well as the point of reference impact. The data from each pair of sensors are then processed to separate the torsional motions from lateral. Because HFTO is a self-excited vibration, it must be validated that this type of vibration is actually excited in the laboratory setup. To demonstrate that the excitation mechanism is representative for the field, one of the test results was used as a reference. A laboratory investigation showed that the measured vibration matches characteristics of self-excited vibrations. Investigations in the laboratory will, therefore, lead to valid solutions in the field.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Well Drilling > Drill Bits > Bit design (1.00)
Creeping Claystone Formation in Absheron Field, Azerbaijan: Description, Issues and Mitigations for Future Wells
Kamalov, K. (Joint Company of Absheron Petroleum, Baku, Azerbaijan) | Mirzayev, R. (Joint Company of Absheron Petroleum, Baku, Azerbaijan) | Kilic, A. (Joint Company of Absheron Petroleum, Baku, Azerbaijan)
Abstract In Absheron appraisal well, a short section (16½″ × 20″) was dedicated to isolate the "Creeping Claystone" troublemaking interval. The creeping shales correspond to a 6 meters thick shale layer compressed between two competent layers of anhydrite. This layer is saturated with water as it is impossible for the fluid to be expelled due to the enclosing anhydrite. The behavior of the shale layer is not considered as over pressured but only as a rheological effect. Only 250 meters were drilled in 16½″ × 20″ section that included "Creeping Claystone" interval. The section was drilled in steps due to previous experienced borehole instabilities. Consequently, a 16½″ pilot hole was first planned to be drilled to TD (Total Depth), then being enlarged to 20″ size. Furthermore, the section was planned to be drilled with 1.67sg NABM (Non Aqueous Based Mud) mud, nevertheless, due to encountered problems with borehole stability, the mud weight was increased by steps up to 1.73sg. Lots of problems were encountered while drilling, such as: several mud overflows from header box in the shaker room after experiencing pack-offs; two SonicScope failures (tool could not withstand such borehole conditions); huge volume (3964.5 t) of cavings, cuttings and mud were recovered, filling 849 skips (4.3 t/skip average). Eventually, 16″ liner was set and cemented at well section TD.
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.69)
Robust Subsurface Drilling Hazards Assessment Reduces Well Drilling Cycle and Geological Non-Productive Time in an Onshore Pre-Caspian Basin Oil Field
Zhumadilov, Ulan (Geologist, TCO) | Baktybayeva, Kalampyr (Geologist, TCO) | Tlepbergenov, Nurbolat (Applied Reservoir Management Team Manager, TCO) | Manakhayev, Ruslan (G&G operations Supervisor, TCO) | Sargunanov, Marat (Advisor Geophysicist, TCO) | Puche, Ernesto (Chevron operations earth scientist)
Abstract Subsurface hazards assessment (SSHA) is an essential part of the well planning stage. Successful well execution depends on reducing geological uncertainties associated with hazards and it might prevent unexpected geological non-productive time (GNPT). Ultimately, SSHA can prevent possible catastrophic wellbore failure and loss of control in the drilling operation. The Pre-Caspian basin with its three megacomplexes has different geological hazards and requires unique drilling practices. Hazard mitigation plan can be developed both during well maturation and execution stages by acting accordingly. The approach should incorporate integrated analysis of geological, geophysical, and drilling data. Detailed SSHA and mitigation plan development are valuable constituents and basements for planning safe and cost-effective execution actions. The GNPT incurred due to insufficient recognition of geological uncertainties and underestimation of hazards can cost extra capital up to 30% of the total well execution expenditure. In addition, detailed SSHA is critical to deliver wells as designed ensuring reservoir penetration, formation evaluation and completion installation objectives are achieved fully, and future production is not compromised.
- North America > United States > New Mexico (0.40)
- Asia > Kazakhstan (0.29)
- Phanerozoic > Mesozoic (0.50)
- Phanerozoic > Paleozoic > Permian > Cisuralian > Artinskian (0.36)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.50)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.68)
- North America > United States > New Mexico > San Juan Basin > Basin Field (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- (7 more...)