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Abstract The challenging nature of drilling and producing shale gas plays has favored the use of oil-based drilling fluids. The growing importance of shale gas has placed greater pressure to address environmental issues associated with the drilling and production of these wells. A pressing goal is the development of a highly inhibitive and environmentally friendly water-based drilling fluid. Specifically, the drilling fluid should address wellbore stability issues associated with specific shale gas plays. Such specialized drilling fluids will better stabilize shales and help control drill time and costs. This paper discusses the research and development of a novel potassium silicate as a shale stabilizer for certain shale gas plays. This novel potassium silicate differs from conventional potassium silicate by significantly increasing the level of dissolved silicate to potassium. The resulting potassium silicate is chemically more reactive and can more easily undergo the polymerization and precipitation reaction. These reactions are the shale stabilization mechanisms most often associated with sodium and potassium silicate. Laboratory investigation indicates drilling fluids formulated with this more vitreous potassium silicate show a high degree of effectiveness at preventing shale delamination and sealing micro fractures. Drilling fluids formulated with conventional potassium silicate can often be disposed using surface methods such as mix-bury-cover, land spreading or land spraying. However, depending on receiving soil or the concentration of potassium silicate in the drilling fluid, it sometimes becomes necessary to treat the associated drill waste with a calcium-based amendment or send the waste to an approved waste management facility. The reduced alkalinity and more siliceous nature of high ratio potassium silicates provides for a drilling fluid with lower salinity as measured by electrical conductivity and sodium adsorption ratio. Resulting drill waste can more easily meet the salinity requirements associated with using surface disposal methods.
- North America > United States (1.00)
- North America > Canada > Alberta (0.29)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Health, Safety, Environment & Sustainability > Environment > Naturally occurring radioactive materials (1.00)
An Innovative Processing Method for High Resolution LWD Density Images in Water and Oil Based Mud
Li, Jing (OXY) | Kennedy, David (PathFinder-A Schlumberger Company) | Dawber, Mike (PathFinder-A Schlumberger Company) | Lee, Rick (PathFinder-A Schlumberger Company) | Boonen, Paul (Boonen-Petro, LLC) | Hollmann, Joseph (Notheastern University)
Abstract With the rapid growth of horizontal drilling, azimuthal LWD bulk-density images (and also photo-electric effect images) have proven to be indispensable tools for the identification of bed boundaries, estimating bed dips, and determining the steering direction of the drilling assembly. The inherent low resolution of the density measurement has, however, typically limited the interpretation of these images to the analysis of structural scale features. The ability to image finer scale detail is governed to a large extent by sampling density. Sampling density depends upon the sampling frequency of the instrument, the rate of penetration of the drilling assembly and the rotary speed of the drillstring. Conventional downhole image processing schemes average raw measurements either in time or depth before sectoring them into relatively large circumferential sectors. This averaging process conserves tool memory and smooths noisy data but inevitably results in the loss of high spatial frequency instrument responses associated with fine scale geological features. Instead of compressing data, we present a method that preserves all the raw measurements stored in the tool memory and maps them to a grid around and along the borehole. Statistical noise is mitigated and a specially designed interpolation scheme is used to fill empty grid locations before analyzing the data and smoothing the results. This methodology allows the creation of high resolution images with up to 256 circumferential sectors and a depth increment as small as 0.6 inches. The technique is equally applicable to borehole image data acquired by any type of logging tool providing that the raw measurements are frequently sampled and stored in the tool memory. For example, high resolution borehole caliper images have also been created from ultrasonic transducer measurements of the same tool used to acquire the data presented in this paper. Azimuthal bulk-density data acquired in this manner allows for the opportunity to produce optimized images in oil-based mud and overcomes the limitations of LWD micro-resistivity imaging tools in non-conductive borehole fluids. This technique has been successfully applied to wells drilled in both the UK North Sea and US land. Field examples presented in this paper illustrate the benefits of the application in imaging thin beds, sedimentary bedding structures, coal seam bedding internal structure, faults and fractures.
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.49)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Louisiana > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Arkansas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- (3 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- (5 more...)
Abstract Much of the drilling in unconventional resource plays occurs in unstable shales, which are usually fractured and can be easily destabilized. Drilling through them successfully can be difficult at best, and many high-angled holes in these plays are often lost due to mechanical instability. This paper examines the problems of shale gas drilling from the theoretical perspective of Wellbore Pressure Management (WPM) and keys in on the effects of equivalent circulating density (ECD) while drilling and on the effects of equivalent static density (ESD) when there is no circulation. In this paper the following questions pertaining to drilling a typical fractured shale or highly-laminated weak zone are addressed from the WPM perspective: What mud density do I need to drill a fractured shale? Why can a typical shale gas play well be drilled with no drilling problems, yet becomes very unstable on the last trip out of the hole before wireline logging or running casing? Why are drilling problems especially acute in laminated shales or similar weak zones? Why is the wellbore unstable while the drilling density is within the range demarcated by the Safe Drilling Window? Why does shale instability often not improve significantly when drilling fluid density levels are increased? Which tools in the driller's toolbox are often used that actually make the wellbore stability issue more problematic? By using a Wellbore Pressure Management approach to understanding instability in fractured shales, the reader can readily see how to best deal with the problem in the field and hopefully improve stability in future wells.
- South America (0.94)
- Europe (0.70)
- North America > United States > Texas (0.69)
- South America > Colombia > Casanare Department > Llanos Basin > Cusiana Field > Mirador Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (24 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management (1.00)
- Well Drilling > Drilling Operations (1.00)
- (5 more...)
Abstract A 3D finite-element model covering more than 10 blocks in the deepwater Green Canyon area of the Gulf of Mexico has been used to calculate the stress distribution around an extensive salt body. The complex model geometry, and the determination of rock properties and pore pressure, was based on multiclient seismic data and state-of-the-art imaging techniques. The model has been used to determine the impact that salt geometry will have on drilling decisions. The numerical model shows that the near-salt stresses are dependent mainly on the morphology of the salt body. Higher compressive stresses were found in supra-salt minibasins and sub-salt concave-down embayments, resulting in higher mud weight windows. Areas below convex-down allochthonous base salt show lower compressive stresses, resulting in narrow mud weight windows. A fast well planning tool has been developed to translate the results of the finite-element model to operational parameters for well design. With this tool, the full stress tensors are extracted along any arbitrary well trajectory, providing a high-resolution model for calculating the mud weight window. This allows the drilling engineer to create fast predictions along any chosen trajectory within the study area and to make quick comparisons of the drilling mud weight window along multiple trajectories, helping with the selection of the optimal wellpath design. The application of this tool is illustrated using a "case study" focused on four proposed trajectories for a hypothetical well that has to reach the Eocene-Paleocene Wilcox formation.
- North America > United States > Texas (0.48)
- North America > United States > Gulf of Mexico (0.34)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.48)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- (4 more...)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract A new solution for determining the amount of mud loss during drilling operation in a fractured reservoir having a regular two- or three-dimensional radial fractured network with the novel inclusion of a convective transport of filtrate in the matrix is presented. Convective-dispersive filtrate transport along the network is modeled in which drilling mud can be filtered in existing matrix. The filter cake effect at the fracture-matrix interface in the network is simulated by means of an empirically decaying filter rate equation. The numerical solution is used in this study. The consistency of numerical solution is checked and the best situation is considered. The sensitivity analysis on all parameters in the model has been done and the effect of each parameters such as wellbore loss rate, reservoir thickness, fracture opening size, matrix porosity, matrix permeability and dispersivity, on the amount of filtration are inversitaged. By means of developed model, the amount of mud filtration can be plotted against position in different fractured network configurations for different wellbore conditions, reservoir properties and reservoir geometries at different times. The position in the fracture network at which the curve of concentration reaches zero can be considered to represent skin radius caused by drilling operation. This radius can be used for determining the acid volume which is needed for acidizing operation and accurate well-log interpretation.
- 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)
- (21 more...)
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Operations (1.00)
- (8 more...)
Summary Highly reactive Fiqa shale used to compel well engineers in the Sultanate of Oman to plan drilling phase of surface and intermediate sections primarily based on time exposure to aqueous drilling fluid water-based mud (WBM). The new approach of drilling the time-dependent Fiqa formation using casing-while-drilling (CwD) allows well engineers to plan prospective top/intermediate wellbore sections differently by enhancing the overall drilling performance. This reduces the risk of setting casing strings at unplanned depths, getting pipe stuck, or reaming continuously when drilling with conventional drillstring. The technical feasibility study, risk assessment, planning, execution, and the lessons learned during the process of drilling two top-section pilot projects are described in this document. The CwD team compares the drilling performance of several offset wells and suggests actions to improve the CwD technology in Oman. Two 17½ - and 22-in. surface sections were drilled successfully with large-diameter casing strings and reached 754- and 894-m measured depths, respectively. The implementation of the CwD concept reduced the overall drill/case phase time up to 40%, in comparison with the average using conventional drilling in those fields. Exposure time of Fiqa to aqueous environment was reduced by eliminating conditioning trips and nonproductive-time (NPT) associated with wellbore instability. Drilling both sections with non-retrievable 17½×13⅜-in. and 22×18⅝ -in. CwD systems did not require modification of well design or rig. The optimization of this technology will support its implementation as the conventional drilling approach in some fields in Oman.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.36)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Fahud Salt Basin > Fahud Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Shell Field (0.97)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations > Running and setting casing (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Casing and Cementing > Casing design (1.00)
Summary Filter-cake characterization is very important in drilling and completion operations. The homogeneity of the filter cake affects the properties of the filtration process such as the volume of filtrate, the thickness of the filter cake, and the best method to remove it. Various models were used to determine the thickness and permeability of the filter cake. Most of these models assumed that the filter cake was homogeneous. The present study shows that the filter cake is not homogeneous, and consists of two layers of different properties. The objective of this study is to measure the filter-cake thickness and permeability of water-based drilling fluids by a new approach and compare the results with previous models. A high-pressure/high-temperature (HP/HT) filter press was used to perform the filtration process under static conditions (225°F and 300 psi). A computed-tomography (CT) scan was used to measure the thickness and porosity of the filter cake. Scanning electron microscopy (SEM) was used to provide the morphology of the filter cake. The results obtained from the CT scan showed that the filter cake was heterogeneous and contained two layers with different properties under static and dynamic conditions. Under static conditions, the layer close to the rock surface had a 0.06-in. thickness, 10- to 20-vol% porosity, and 0.087-pd permeability, while under dynamic conditions, this layer had a 0.04-in. thickness, 15-vol% porosity, and 0.068-pd permeability. The layer close to the drilling fluid had a 0.1-in. and 0.07-in. thickness under static and dynamic conditions, respectively, and it had zero porosity and permeability after 30 minutes under static and dynamic conditions. SEM results showed that the two layers contained large and small particles, but there was extremely poor sorting in the layer, that was close to the drilling fluid, which led to zero porosity in this layer. Previous models underestimated the thickness of the filter cake by almost 50%. A new method was developed to measure the thickness of the filter cake, and various models were screened to identify the best model that can predict our permeability measurements.
- Overview > Innovation (0.54)
- Research Report > New Finding (0.48)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.89)
- North America > United States > Texas > Permian Basin > Yates Formation (0.89)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.89)
- (21 more...)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
Abstract The Haynesville shale presents special challenges when designing cement systems. Extended-reach, horizontal wellbores create a high-pressure/high-temperature (HP/HT) environment not conducive to conventional cement slurries. Tight annular clearances and a narrow pore-pressure/fracture-gradient window have forced the industry to push the boundaries of cementing theory. Cement designs with a latex additive have improved rheological characteristics that yield lower equivalent circulating densities (ECDs) and reduce the frictional coefficient necessary for manageable surface pressures. The latex-based designs are thermally stable up to 400°F and provide excellent fluid-loss control, while still improving surface mixability. Most of the desired properties are observed when the cement is liquid; the set cement sheath can also provide corrosion resistance, annular bonding, and elasticity for well cycling. The development, testing, and case histories of latex-based cement slurries are discussed in this paper and compared to conventional cement designs for horizontal applications. By improving the physical properties of the cement while it is still in a fluid state, the cement can be properly placed, thus decreasing the potential for job failures. With the fluid viscosities enhanced, the pump rates can be optimized using hydraulic modeling to obtain increased mud-displacement efficiency. Laboratory testing has shown the latex additive to be effective from 1 to 2.5 gal per sack of cement. The latex additive enhances several cementing properties and reduces the need for additional fluid modifiers. By reducing the additives in the blend, the testing variability is decreased and repeatability is increased. Similar designs have been used in the past, but failure to maintain system stability created limitations. With new technology and theory, a heavyweight, thermally stable cement can be pumped during the most adverse well conditions.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (0.71)
- Geology > Geological Subdiscipline > Geomechanics (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.62)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.61)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
- (3 more...)
Abstract In recent years, drilling and production activity in US shale gas has been increasing. This high volume of work has led to the use of manufacturing-style well construction. Each area has its own challenges; however, problematic wells are prevalent in many shale plays. A major study in the Haynesville shale targeted the manufacturing-style methodology. Over the course of the study, more than 160 cement jobs were analyzed including surface, intermediate and production strings. This study implemented the use of careful engineering decisions that were focused on the issues and challenges specific to wells in this area. This was achieved through analyzing and optimizing the laboratory operations, design of cement systems, bulk plant and job site processes. This study shows by taking the proper steps to design these processes, a manufacturing style approach can be very successful when applied in challenging shale cementing operations.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.88)
- North America > United States > Texas > Haynesville Shale Formation (0.98)
- North America > United States > Louisiana > Haynesville Shale Formation (0.98)
- North America > United States > Arkansas > Haynesville Shale Formation (0.98)
- (12 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
Abstract In preparation of a gelant solution for making crosslinked polymer gels for water shutoff applications, unpublished experiments and chemical intuition suggest that, unless hydrolyzed polyacrylamide (HPAM) polymer is fully hydrated before addition of crosslinker, the final gel will have lower than optimum mechanical strength, presumably because polymer chains need to be fully unfolded before proper crosslinking can occur. When using dry polymer, which is usually the lowest cost form on a delivered basis, this may require more equipment and a large tankage footprint. However, if conditions exist where crosslinker can be added to wetted but not fully hydrated polymer, then dry polymer and crosslinker can be blended in a small continuous flow unit, with full hydration occurring as the gelant flows downhole prior to gelation. We have evaluated gel strengths of "flowing" gels for water shut off in natural fractures and other non-matrix features as a function of time of addition of crosslinker relative to time of hydration of polymer. Gels were prepared from moderately high molecular weight HPAM crosslinked with chromium(III) acetate (CrAc) or polyethyleneimine (PEI). Crosslinker was added after either (1) initial wetting of solid polymer particles or (2) complete dissolution of the polymer. Gel strengths were determined using a common qualitative coding system. Comparisons were made for gels prepared in an identical manner, except for the timing of crosslinker addition. Samples were prepared either in fresh water or 4% NaCl brine and then hydrated either at an ambient temperature or 122 °F. Gelant viscosity and crosslink time were also characterized with a viscometer. Results of this work demonstrate that for most field applications using CrAc as crosslinker, optimum quality gel can be obtained using dry polymer and a small continuous mixing system for initial wetting of the polymer, after which the crosslinker can be added to the polymer solution on-the-fly. This practice can decrease the footprint and cost of large volume flowing gel treatments.
- 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)
- (21 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)