Direction Of Wellbore Research Articles

Predicting The Azimuth of Stress from Wellbore Breakouts in (X) Oil Field

The current minimum and maximum horizontal stresses orientations are influential parameters in the development of any Geomechanical model; these models aim to reduce wellbore instability and non-productive time during drilling by selecting the best wellbore direction when drilling inclined or horizontal wells. Minimum horizontal stress orientations can be established by examining wellbore breakouts. Borehole breakouts result from a natural failure compression process in which the maximum hoop stress surrounding the hole exceeds the rock strength, which may be detected using an oriented caliper log tool. There is no data in the World Stress Map (WSM) in the research area. As a result, data from 10 wells in the (X) oilfield's Oriented caliper well logs were analyzed for this study. The breakouts azimuth is consistent with depth, and the minimum horizontal stress azimuth from the north is 140o - 150o and 320o - 330o, which is compatible with the regional maximum horizontal stress direction (Shmax). As a result, the recommended drilling direction of deviated, and horizontal wells in the (X) oil field area should parallel the maximum horizontal stress.

CALCULATION OF FRACTURE INITIATION DIRECTION IN PERFORATED WELL

The work considers the issue of initiating the fracture and its direction in the formation during the hydraulic fracturing operation during the development of the field. Based on the analytical decision on the stress state of the cylindrical channel in the loaded medium, an algorithm is built to calculate the direction of fracture initiation in the case of a well with a set of perforations. The algorithm considers two acceptable scenarios: the fracture can be initiated either by fracturing the wellbore or by fracturing one or more perforations. In addition to the direction of fracture formation, the algorithm allows you to calculate the formation pressure, as well as the final closing pressure of the frac crack. The work also analyzed the effect of wellbore direction on fracture parameters in several different versions of well geometry with perforation channels. The calculations show a significant effect of wellbore direction as well as Poisson ratio on the result of wellbore rupture. The contrast of the main stress tensor components transverse to the well axis also has a significant impact on the direction of fracture initiation. The developed method allows you to determine the direction of the frac fracture for combinations of wellbore trajectories and perforations. The final configuration of the perforation channels has some uncertainty about the specific direction of the channels, since in practice control of the direction of the device is rarely used. To reduce the risks of incorrect assessment of rupture parameters, the algorithm is supplemented with a sensitivity analysis to the direction of the perforation channel system. The algorithm is implemented as a separate Python program module.

Subsection and superposition method for reservoir formation damage evaluation of complex-structure wells

Kinds of complex-structure wells can effectively improve production, which are widely used. However, in the process of drilling and completion, complex-structure wells with long drilling cycle and large exposed area of reservoir can lead to the fact that reservoir near wellbore is more vulnerable to the working fluid invasion, resulting in more serious formation damage. In order to quantitatively describe the reservoir formation damage in the construction of complex-structure well, taking the inclined well section as the research object, the coordinate transformation method and conformal transformation method are given according to the flow characteristics of reservoir near wellbore in anisotropic reservoir. Then the local skin factor in orthogonal plane of wellbore is deduced. Considering the uneven distribution of local skin factor along the wellbore, the oscillation decreasing model and empirical equation model of damage zone radius distribution along the wellbore direction are established and then the total skin factor model of the whole well is superimposed to realize the reservoir damage evaluation of complex-structure wells. Combining the skin factor model with the production model, the production of complex-structure wells can be predicted more accurately. The two field application cases show that the accuracy of the model can be more than 90%, which can also fully reflect the invasion characteristics of drilling and completion fluid in any well section of complex-structure wells in anisotropic reservoir, so as to further provide guidance for the scientific establishment of reservoir production system.

Complexity of near-wellbore hydraulic fracture morphology around perforated wells with various orientations in tight reservoir

Horizontal wells with multiple perforated fracturing is main method to improve well production in the tight formation. However, hydraulic fracture morphology remains obscure because of different horizontal stress contrast, wellbore direction, and pump rate, resulting in no guidance for perforation parameters design. To uncover the mask, a perforated wellbore fracturing model is established based on the continuous damage theory, combing with field data to investigate the effects of above three factors on hydraulic fracture morphology around wellbore. The results indicate that induced fractures could overlap and interact with each other when the wellbore is set along the direction of minimum horizontal stress. The induced fractures have narrow width because of stress shadow effecting. However, when angle between wellbore and the minimum horizontal stress direction increases, the induced fractures prefer to link up as a simple one. Moreover, induced fractures could propagate along and perpendicular to the wellbore direction under a small horizontal stress contrast, forming a complex hydraulic fracture morphology. A high pump rate resists stress shadow effecting and improves hydraulic fracture volume, but cannot decrease the complexity of near-wellbore fractures under a small horizontal stress contrast.

Risk assessment of packed holeassemblies for rotary well drilling

The main elements of the statistical model of packed hole assemblies (PHA) design for drilling holding sections in the conditions of information uncertainty have been formalized and described. Сonstraints ystem has been given for angle maintain conditions of wellbore direction and dynamic stability of bottom hole assembly (BHA) lateral vibrations. The influence of information uncertainty of some factors (angle, parameters of the drilling practice, presence of local caverns, etc.) on risk indicators has been analyzed according to the results of numerical calculations. It has been specified that the risks of angle maintenance disturbance are significantly influenced by the angle and the weight on the bit (WOB), and dynamic stability conditions, such as angle and rotation frequency. Risks of multi-supported BHAs which have been designed for conditions of bit side force minimizing, dynamic stability and include 4 – 6 stabilizers.

Experimental Study of Volumetric Fracturing Properties for Shale under Different Stress States

Shale gas can be commercially produced using the stimulated reservoir volume (SRV) with multistage fracturing or multiwell synchronous fracturing. These fracturing technologies can produce additional stress fields that significantly influence the crack initiation pressure and the formation of an effective fracture network. Therefore, this study primarily investigated the evolution of crack initiation and propagation in a hydraulic rock mass under various stress conditions. Combining the in situ stress characteristics of a shale reservoir and fracturing technology, three types of true triaxial volumetric fracturing simulation experiments were designed and performed on shale, including three-dimensional constant loading, one-dimensional pressurization disturbance, and one-dimensional depressurization disturbance. The results indicate that the critical failure strength of the shale rock increases as the three-dimensional constant loads are increased. The rupture surface is always parallel to the maximum principal stress plane in both the simulated vertical and horizontal wells. Under the same in situ stress conditions in the wellbore direction, if the lateral pressure becomes larger, the critical failure strength of shale rock would increase. Additionally, when the lateral in situ stress difference coefficient is smaller, the rock specimen has an evident trend to form more complex cracks. When the shale rock was subjected to lateral disturbance loads, the critical failure strength was approximately 10 MPa less than that in the state of constant loading, indicating that the specimen with disturbance loads is more likely to be fractured. Moreover, shale rock under the depressurization disturbance load is more easily fractured compared with the pressurization disturbance. These findings could provide a theoretical basis and technical support for multistage or multiwell synchronous fracturing in shale gas production.

An innovative concept on deep carbonate reservoir stimulation: Three-dimensional acid fracturing technology

Acid fracturing is an indispensable technology in the efficient development of carbonate oil and gas reservoirs. As for deep and ultra-deep marine carbonate oil and gas reservoirs, however, existing acid fracturing technologies can hardly create complex fracture networks because of their particular engineering and geological characteristics. In order to realize the efficient three-dimensional development of deep and ultra-deep marine carbonate oil and gas reservoirs, this paper revealed the acid fracturing difficulties of this kind of reservoirs based on the engineering and geological characteristics of deep marine carbonate oil and gas reservoirs in China. Then, by taking the efficient three-dimensional development of deep and ultra-deep marine carbonate oil and gas reservoirs as the target, the technical concept of three-dimensional acid fracturing (3D-AF) was put forward based on the techniques of volume acid fracturing and deep acid fracturing. In addition, its technical connotation was illustrated, and its key technologies were described in detail. Finally, its development direction in the next step was pointed out. And the following research results were obtained. First, the 3D-AF technology contains three basic connotations: (1) selecting the corresponding acid penetration technology according to reservoir types so as to realize sufficient reservoir stimulation on the plane; (2) creating complex acid-fracture volume with higher flow conductivity under high closed pressure; (3) deploying acid-fracture volume rationally along the long hole section so as to realize sufficient reservoir stimulation in the wellbore direction. Second, there are three key technologies of 3D-AF, i.e., the technology for predicting the effective acid-penetrate distance under the coupling action of multi-field, multi-scale and multi-fluid, the technology for optimizing the flow conductivity of complex acid-fracture volume, and the technology for precisely deploying acid in the long section of horizontal well or highly deviated well. Third, in order to promote the further development of 3D-AF technology, it is necessary to carry out researches on three technologies, i.e., the technology for predicting and reducing the fracturing pressure of ultra-deep reservoir, the technology for predicting the geometry of acid-fracture body in a strongly heterogeneous reservoir, and the staged reservoir production technology and new fluid technology with high temperature resistance, low reaction rate and low friction resistance coefficient for long hole sections (over 7000 m).

Evaluating seepage radius of tight oil reservoir using digital core modeling approach

The main development method of tight oil was depletion development. It is determined that the seepage radius of tight reservoir is crucial to the layout and prediction development of tight oil development. Since the pore throat level of tight reservoirs was frequently nanoscale, the reservoir pressure propagation velocity was even faster than conventional medium high permeability. The fracture system in the tight oil reservoir, which is the main flow channel of oil flow to the direction of wellbore, is more sensitive to the sharp change in reservoir pressure. Hence, the stress-sensitive absolute permeability of the reservoir near the wellbore will fluctuate significantly during the depletion development phase, rather than a constant value. At present, the numerical simulation and graph method, which are commonly utilized in the regression and prediction of the depletion-developing seepage radius. Both do not consider the stress sensitivity phenomenon which caused by nanoscale pores of tight oil and the change of the permeability in the model. As a result, the prediction is not accurate and the model needs to be modified. Meanwhile, the percolation parameters at the scale of the tight oil permeability cannot be accurately obtained in using conventional experimental methods owing to the limitations of the accuracy of the experimental instruments. In this paper, the test of fluid permeability under overburden was carried out to verify the stress sensitivity of the tight core. The microscopic mechanism of nanoscale pore-throat stress sensitivity in tight reservoirs was analyzed from the perspective of tight reservoir mineral composition and nanopore characteristics by using Quantitative Evaluation of Minerals by Scanning Electron Microscopy (Qemscan) and MAPS micro-image splicing technology. Nanoscale pore network model was established with nano-CT scanning and the digital core seepage simulation of tight core was figured out. The accuracy of the digital core seepage simulation method was verified in comparison with the indoor over pressure liquid permeability test. The conventional reservoir model was modified by using the digital core seepage simulation result, and the new model has a high degree of confidence in predicting the tight oil seepage radius.

Microseismic monitoring of Vaca Muerta completions in the Neuquén Basin, Argentina

The Vaca Muerta shale oil play in Argentina's Neuquén Basin is expected to make a large contribution to Argentina's hydrocarbon production in the future. In 2013, the U.S. Energy Information Administration estimated that the Vaca Muerta had technically recoverable reserves of 308 Tcf gas and 16 billion bbl of oil and condensate, making it the third largest shale oil reservoir in the world at that time. Wintershall Energia has been active in the Neuquén Basin since 1994. In 2014, it acquired a controlling interest in the Aguada Federal block with an intention to exploit the Vaca Muerta oil shale occurrence within that block. At the outset of its development program, Wintershall decided to incorporate microseismic monitoring to help understand completions in the Vaca Muerta. Monitoring of the completion of vertical well AF.x-1 was accomplished with a surface array. The goal of the monitoring was to inform later decisions on horizontal wellbore direction, wellbore and stage spacing, and landing depth. Results of the surface array monitoring were also used in the design of a permanent buried array intended to monitor subsequent development wells. The buried array was installed in September 2016 and consists of 126 stations spread at an interval distance of approximately 500 m over an area of roughly 5 by 7 km. Each station has geophones placed over a depth range of 20 to 50 m subsurface. The first two horizontal development wells in the project, AF.x-4h and AF.x-9h, were completed in late December 2016 and early January 2017. The second set of two wells, AF.x-3h and AF.x-7h, was completed from May to June 2017. The 4h and the 7h were landed in the upper Middle Vaca Muerta while the 9h and 3h were drilled about 100 m deeper, landing still in the Middle Vaca Muerta. The lateral length of each well was approximately 1000 m, and each was completed with 11 plug-and-perf stages. Stage length and interval were varied along the wells to test various completion strategies. The completions of all four wells were successfully monitored using the buried array. These microseismic data provide a detailed description of the fracture network created by the treatments. Focal mechanisms determined for the detected events have been used to understand the stress distribution in the reservoir and to further refine the completion parameters for future development wells.

Determination of safe mud pressure window for different well trajectories and stress regimes during drilling operations

Wellbore stability is one of the crucial issues in oil and gas industries. The issues related to instability of wells, impose significant unwanted costs on drilling operation. Several studies have been undertaken about borehole stability and optimized wellbore direction. However, the majority of them are focused on shear and tensile failures induced instability separately. and there are Only a few studies address with these two failures induced borehole instability during drilling simultaneously. The objective of this paper is to determine the safe mud pressure window required to stabilize the wellbore in different well trajectories and in-situ stress regimes during drilling operation using the Hubbert–Willis and 3D Hoek–Brown criteria. The results indicate that in different in-situ stress regimes, the inclination and azimuth have a significant role in wellbore stability during drilling. It was found that, the most stable drilling direction is along the minimum horizontal stress for the extensional stress regime, while it is along the maximum horizontal stress in the strike-slip and compressional stress regimes. Furthermore, for the extensional, strike-slip and compressional stress regimes, the most stable path are respectively: deviated, horizontal, and again horizontal. Such borehole stability analysis plays an important role in the design of oil and gas well drilling.

Decision-Oriented Geosteering and the Value of Look-Ahead Information: A Case-Based Study

Summary Geosteering techniques have been widely implemented in the oil and gas (O&G) industry for well-placement operations. These techniques allow the operators to apply real-time information in precisely controlling the wellbore direction to stay within desired reservoir zones. The industry has mainly focused on technological improvements of real-time technologies. Nonetheless, previous work has indicated that the conventional approach for making geosteering decisions leaves much to be desired. Normal geosteering operations involve drawing inferences from behind-the-bit information to ahead-of-the-bit reservoir uncertainties and making decisions under unresolved uncertainties to optimize a single objective or multiple objectives. On the basis of a large body of research, the conventional approach—which is heavily driven by intuitions, educated guesses, and approximate methods (rules of thumb)—is unlikely to identify the optimal courses of action. Geosteering decisions are sequential decisions made under dynamic uncertainties. A sequence of well-trajectory decisions arises as the well penetrates the formation and real-time data are gathered. To optimize decision making in such an environment requires considering future decisions and uncertainties, along with the flexibility to take action as new information is learned. In this work, we demonstrate how sequential geosteering decisions can be optimized by use of the discretized-stochastic-dynamic-programming approach (DSDP). DSDP exploits the benefits of stochastic dynamic programming to optimize multistage, interrelated decisions under uncertainties. At the same time, the computational time is minimized so it can be applied to geosteering decisions. Through case studies, we illustrate the application of DSDP in various reservoir structures. The results suggest that the technique could significantly improve the final results of the wells, especially if the reservoir boundaries change rapidly or in a faulted reservoir. The results are expressed as substantial increases in resulting reservoir contacts as well as reductions in well-construction costs. Finally, we illustrate and discuss the use of DSDP to assess the value of look-ahead information. We demonstrate that merely increasing the look-ahead capability (ahead-of-the-bit distance that the tool can measure) is not sufficient. The values created from look-ahead are also strongly affected by the measurement accuracy and the flexibility to respond rapidly by making large directional changes.

Analysis of Fractured Reservoir Structure by Interpretation of FMI and VSP Logs

Imaging technology into the well is the tools for logging system, interpretation of data obtained from the well and to create the image with high resolution from the wells. This technology creates an accurate image (screenshot tools and the vertical seismic) on structural characteristics, layering, fractures, faults, texture and secondary porosity play an important desirable role in describing the reservoir. In the carbonate reservoirsthat most of Iran reservoirs are included in this type fractures are the most important factor in the production of these reservoirs. In the fractured carbonated reservoirs faults and folds makes unwanted changes in the structure of these reservoir. Structural complexities occur at different scales. For example, major faults and the original boundaries between formations are visible on the surface seismic data. But small-scale changes and faults in seismic data cannot be determined and it is essential to use small-scale of data and information sources. For achieving to these purposes it can be combined the result of small-scale data such as internal wellbore seismic VSP (vertical seismic profile) that having separating power in meter limit and FMI (formation micro imager) imaging logs that having separating limit in centimeter limit that could be able to modeling structural complexities and distribution of fractures around well. It should be noted that identifying occurrences around the wellbore is very important in drilling, completion procedures and development programs. FMI (formation micro imager) logs can be directly determined the inverted changes of wellbore layers and formation structures and also was an important factor for stratifying layers and determining the lithology of oil and gas explorations that can be determined the wellbore fractures, inclination and direction by using its interpretation. Moreover VSP (vertical seismic profile) logs is the way that generated signals at the surface are received by the geophone at different depth levels in the wells, which by its interpretation; changes in wellbore direction, velocity profiles, faults with higher accuracy around the wells and fractures around the well can be determined.

Classification Prediction Method Used in Coal Crushing

Coal principal stresses with reservoir plane is analyzed, consequently coal seam crushed classification method is presented based on Hoek-Brown criterion. According to the coefficient of coal crushing, coal seam crushed coefficient size, four grades of A,B,C,D are divided for coal crushed degree along wellbore direction, and coal crushed classification standard is determined. Using the classification method and standard, the distribution regularity of coal crushing is studied for ZP-05 Well in QinShui basin. The research results show that coal crushing of ZP-05 is considered as grade B. The prediction results agree well with the measured values.

Determination of optimal well trajectory during drilling and production based on borehole stability

Several studies have been done about borehole stability and optimized wellbore direction. However, the majority of them focused on stability during drilling, and there are only a few studies concerns with stability during drilling and production and its problems such as sanding simultaneously. This paper presents an analytical model that estimates collapse pressure in stability analysis during drilling and in addition determines maximum drawdown pressure to prevent sand production, using the Mogi–Coulomb failure criterion. The results show that in different in-situ stress regimes, the inclination and azimuth have a significant role in wellbore stability during both drilling and production. Furthermore, the results show that the optimum direction for wellbore stability during drilling is also the best direction for stability of a production well. The analytical model is applied to field data in order to verify the applicability of the developed model.

Prediction Method of Coal Fracture Based on Failure Approach Index and Hoek-Brown Criterion

According to Mohr-Coulomb criterion, the yield approach index (YAI) of Hoek-Brown criterion is derived. The rock-mass intact coefficient KV is introduced, and coal failure approach index is defined by combining failure degree. On the basis of logging data and stratified in-site stress model, the failure approach index and yield approach index are calculated in wellbore direction. Based on FAI values, coal fracture degree is divided four grades of A, B, C, D, and coal fracture classification method is proposed. Taking ZP-1 Well in QinShui basin as an example, the distribution regularity of coal fracture degree is predicted by the method. The results indicate that failure approach index of ZP-01 well is between 0.8-1.2; the section of 551-552.7m of coal seam is fractured (grade A), and the rest section of coal seam is regarded as grade B. Through electron microscope to scan coal sample structure, the results agree well with the prediction results, therefore the classification method is reliable. Depending on theory results, computer program is corresponding developed.

Wellbore Surveying While Drilling Based on Kalman Filtering

Problem statement: Oil and gas are global fuels obtained primarily from drilling wells in underground terrestrial reservoirs. Vertical drilling is preferred because of its simplicity and therefore low cost, but subsurface targets can often be procured only by directing the wellbore along predefined non-vertical trajectories. For instance, directional drilling must be employed to reach locations inaccessible to the drilling rig, to side track an existing well (multilateral drilling), or to drill multiple wells from the same offshore platform (horizontal drilling). Approach: A complete knowledge of the wellbore direction and orientation during the drilling process is essential to guarantee proper directional drilling procedure. Results: Thus, besides the conventional drilling assembly, directional drilling operations require sensors to provide azimuth, inclination and toolface angles of the drill. These sensors are part of the Measurement-While-Drilling (MWD) tool, which in current technology is installed several feet behind the drill bit. In such systems, values for inclination and toolface angles are determined from accelerometer measurements at predetermined stationary surveying stations; these values are then incorporated with magnetometer measurements to deliver the azimuth angle. Values for inclination and azimuth angles at the current surveying station are combined with those from the previous station to compute the position of the probe. However, there is no accurate information about the wellbore trajectory between survey stations. Additionally, the magnetic field of the magnetometers has deleterious effect on the overall accuracy of surveying measurements. Conclusion: A method to provide continuous information about the wellbore trajectory has been developed in this study. The module developed integrates a Rotary Steerable System (RSS) and MWD tool into one drilling probe utilizing Inertial Navigation System (INS) technology. This is achieved by designing a reliable real-time low cost MWD surveying system based on MEMS inertial sensors miniaturized inside the RSS housing installed directly behind the drill bit. A continuous borehole surveying module based on MEMS inertial sensors integrated with other drilling measurements was developed using Kalman filtering.

WELL-BORE INSTABILITY IN THE NORTH WEST SHELF OF AUSTRALIA

Well-bore instability, experienced mainly in shales, has resulted in significant drilling delays and abandonment of wells in the North West Shelf of Australia. Although these problems may be induced by physico-chemical interactions, there is an increasing awareness that instability in this region is principally associated with in situ stresses that are high relative to the strength of the materials.This paper describes the research undertaken by the Australian Petroleum Cooperative Research Centre to assist industry in understanding and managing stress-induced well-bore instability in this region. To conduct such stability analyses the basic information required includes knowledge of the orientation and magnitude of the principal in situ stresses and the strength and deformation response of the materials to stress changes imposed by drilling. The required data can be determined using welllogging, analytical and laboratory techniques.Analytical methods can be used to examine the relationship between well-bore stability and changes introduced through drilling. Spreadsheets based on the analytical methods have been produced and applied to the assessment of drilling alternatives and/or design of some well-bores in the North West Shelf.The application of the critical mud weight contour plots and mud weight stability profiles produced by the spreadsheets in assessing drilling alternatives, selection of optimum well-bore alignment and mud weight design are demonstrated through examples. The analyses showed that counter to intuitive expectations, an inclined well may be more stable than a vertical well depending on the well-bore direction, deviation angle and stress regime.