The auroral zone is the region surrounding the geomagnetic north and south poles and is where the largest and most frequent disturbances in the Earth's magnetic field are experienced. Since the accuracy of magnetic MWD directional surveys are affected by geomagnetic disturbances, surveying wells in the auroral zone is challenging. Development of industry practices to enable accurate surveying and safe operations in these areas is therefore important.
The objective of this study is to investigate how the geomagnetic field parameters declination, dip angle and total magnetic field intensity are influenced by magnetic disturbances in the auroral zone. This is done by analysing the statistical properties of data from 20 land-based magnetic observatories and variometer stations in Alaska, Greenland, and Scandinavia, all located in the auroral zone. The results are used to estimate models for magnetic field disturbance variations as function of distance and direction. Additionally, methods and correction procedures to reduce azimuth uncertainty using data from distant monitoring stations are presented.
Uncritical use of data from monitoring stations can result in uncertain azimuth measurements. In cases where data from more than one nearby monitoring stations are available, the challenge is often related to identifying which stations that provide the most accurate corrections. As will be shown, important criteria for the selection of monitoring stations are not only limited to directions and distances, but also the position of the ionospheric current relative to the rig-location. Procedures and methods for how to predict the positions of ionospheric currents are presented.
The datasets analysed in this study contain measured deviations from the quiet mean for periods with low, moderate and high geomagnetic activity. Station-pairs with mutual distances ranging from 150km to 850km are considered. The general trends are that magnetic data from station-pairs located along the east-west direction are more correlated than data from stations located along north-south, and that differences in magnetic fluctuations between station-pairs are lower east-west than north-south. This accounts for all distances, directions, and disturbance levels.
Maidla, Eric (ProNova - TDE Petroleum Data Solutions, Inc.) | Maidla, William (ProNova - TDE Petroleum Data Solutions, Inc.) | Rigg, John (ProNova - TDE Petroleum Data Solutions, Inc.) | Crumrine, Michael (ProNova - TDE Petroleum Data Solutions, Inc.) | Wolf-Zoellner, Philipp (ProNova - TDE Petroleum Data Solutions, Inc.)
The authors have been contacted by many people in the industry lately that are incorrectly utilizing big data to produce correlations that attempt to identify operational "sweet spots". This paper will show examples and address the need to add several steps to big data before any meaningful correlation results can be obtained, mainly understanding (and this is not a comprehensive list): The sensors involved and their limitations; The errors in the placement of these sensors (e.g. hook load sensor on the deadline); The frequency of the data and how this impacts the analysis (some companies provide 10-second data); The quality of the data itself; The appropriate filtering of data to ensure apples-to-apples comparisons; The rig state must be known Understanding of the physics involved.
The sensors involved and their limitations;
The errors in the placement of these sensors (e.g. hook load sensor on the deadline);
The frequency of the data and how this impacts the analysis (some companies provide 10-second data);
The quality of the data itself;
The appropriate filtering of data to ensure apples-to-apples comparisons;
The rig state must be known
Understanding of the physics involved.
Cores can be considered the ground truth only if we eliminate or minimize their damage during the core cutting, tripping, and surface handling. Such damage would adversely alter their properties. An important source of core damage is during tripping when the quick decompression may cause damage due to the induced microfractures. In this paper, a state-of-the-art geomechanical model is introduced and applied for determining the safe tripping rates.
The Thermo-Poro-Elastic (T-P-E) geomechanical approach used in this study includes the mathematical derivation of the diffusion time required for the imposed pore pressure difference to dissipate while also considering the effects due to the temperature changes, the mud cake, and swabbing. The work utilizes different approaches for fluid modeling in a transient manner during tripping for the water-bearing, gas- bearing, and oil-bearing cores.
In this work, the hydraulic diffusivity and the fluid type have been introduced as the main factors controlling the maximum allowable safe tripping rates. A relationship between the allowable decompression rate and the hydraulic diffusivity will be presented for each specified fluid type. In addition, the results indicate that water-bearing cores can be safely tripped as quickly as the normal tripping speed of the wireline, even with core permeabilities of as low as 0.01 mD. For gas and oil-bearing cores, the safe tripping rates are determined to be much less than the water-bearing cores as the fluids expand with pressure drop along its journey to the surface. The results show that the tripping rate is the lowest for the oil-bearing cores particularly in the vicinity of the bubble point and gas critical pressure (as the gas expansion pushes the oil and applies significant viscous forces across the core pore throats).
This paper is a novel work developing T-P-E and mathematical models for the case of core tripping considering the effects of the pore pressure change, temperature change, the mud cake, and swabbing. The hydraulic diffusivity and the fluid type have been considered as the controlling factors. The approach has been applied for modeling the tripping of water, gas, and oil-bearing cores to provide maximum allowable tripping rates.
A statistically rigorous assessment of the effect of fracturing treatment chemical additives on well productivity was performed. The dataset for analysis consisted of over 4,500 slickwater-treated wells in the lower 48 US states. All wells were treated by a single service company within a 5-year period. The analysis focused on two distinct additives, namely, linear guar gels and surfactant-based flowback aids, in slickwater treatments. A method and workflow to quantify the effects of completion parameters on well productivity were developed in this work. The statistical
Meza, O. Grijalva (Institute of Petroleum Engineering, Clausthal University of Technology) | Kamp, K. (Institute of Petroleum Engineering, Clausthal University of Technology) | Asgharzadeh, A. (Institute of Petroleum Engineering, Clausthal University of Technology) | Bello, O. (Institute of Petroleum Engineering, Clausthal University of Technology) | Freifer, R. (Institute of Petroleum Engineering, Clausthal University of Technology) | Oppelt, J. (Institute of Petroleum Engineering, Clausthal University of Technology)
The technique of drilling a wellbore by using casing instead of drill pipe (Casing Drilling-CD) is gaining in relevance within the Oil & Gas sector since its implementation in the last decades. This technique, aside from the evident reduction in drilling time and costs observed whenn applied is convenient to minder the effects of certain while-drilling issues as those arising while drilling unstable formations. The focus of concern in this work will be the geometry-related aspects of Casing Drilling influencing not only the drilling operation itself but its particular well control needs as well; this latter will be explained in detail.
A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and to avoid colliding with other offset wells. The selection of the wellbore survey tools within the survey program are limited to the current accuracy available to the industry. A newly developed wellbore survey technique has proven to have superior accuracy compared to the current standard measurement-while-drilling (MWD) surveys with in-field referencing and multi-station analysis (MSA).
In almost every drilling bottom hole assembly (BHA), there is an MWD survey tool to survey the wellbore while drilling. Accuracy of the MWD surveys has been improved over the years by correcting potential error sources such as misalignment of the survey package from the borehole, drillstring magnetic interference, limited global geomagnetic reference, and gravity model accuracy. This new positioning technique takes the accuracy of MWD surveys to the next level by combining surveys from two independent survey packages. The second survey package is installed inside the rotary steerable system (RSS). Surveys from both packages are retrieved while drilling.
Results have been obtained from multiple runs worldwide, enabling comparisons between the new technique and standard MWD surveys from both an enhanced accuracy and true wellbore placement point of view. A proposed error model is based on both the theoretical improvements in accuracy and the empirical proof from the data analyzed. The improved accuracy while drilling assures higher confidence that the well placement will maximize reservoir production and avoid collision with nearby offset wells.
In reservoir sections, the wellbore survey accuracy limits the lateral spacing, and this constrains the reservoir production. In top and intermediate sections, wellbore survey accuracy limits the well plan, and this affects how close the well can be drilled in proximity to other offset wells. This directly impacts the complexity of the directional work and the cost per drilled foot. The new technique unlocks the potential to significantly improve the wellbore positioning accuracy.
It is common in unconventional plays to have offset wells with very different productivity, even though these wells were drilled at the same time, in the same landing zone and with the same completion design. Such well behaviour is always puzzling because subsurface properties are not expected to vary significantly at a small scale.
This problem has been identified in several pads in the Utica play. To try to understand this phenomena, a geological and statistical analysis has been performed on more than 400 wells and 7000 stages. The results show that differences between offset wells occur mainly when the two wells have their stages placed in slightly different facies. More precisely, we show that within a 40 feet thick landing zone, stages can be placed in 3 types of facies: (a.) facies A with a gamma-ray (GR) of ~70°API (~40% Vclay), (b.) facies B with a GR of ~60°API (~20% Vclay) and (c.) Facies C with a GR of ~50°API (~5% Vclay). Generally, for a given well, if more than 50% of its stages are in facies A, the production is 15% lower than a well with no stages in facies A.
Analysis of pressure data from completion indicate that the productivity decrease originates from limited fractures propagations when the completion is initiated in the clay-rich facies. Stages completed in facies A show a high near well-bore pressure loss and a low net pressure, which is consistent with the notion of shale choke, where fracture propagation is limited to the near well-bore. On the contrary, stages placed in the brittle facies C show high net pressures and low near well bore pressure losses, consistent with well- developed fracture geometry in the far-field. This difference in hydraulic fracture geometry could explain the difference in production between two neighboring wells.
Such results are important because it shows that stage placement is critical to productivity, even when the well has been accurately geosteered in the target zone. Optimizing the completion design by accounting for the heterogeneities should therefore significantly improve productivity and guide operation strategy.
In most US unconventional basins, operators often start development by drilling the minimum number of wells needed to hold their acreage. These initial wells are sometimes called "parent" wells. Operators then start drilling their infill development wells, which many operators are currently in the process of doing across various unconventional basins. Infill performance can be highly variable, with operators making great efforts to ensure infill wells perform comparable to or better than existing parent wells. This challenge will become more magnified in the unconventional industry as infill development surpasses parent well drilling. To add more uncertainty, limited research exists showing basin-wide trends as to how infill wells can be expected to perform on average in comparison to their parent well counterparts. We studied infill well performance in numerous US basins, with the objectives of understanding performance trends and their causes, along with providing recommendations for maximizing infill well potential.
We evaluated the performance of newly drilled infill wells compared to their parent wells, which had been produced for some time. With publicly available production and well information, an evaluation was performed for the following major unconventional basins: Bakken/Three Forks, Barnett, Bone Springs, Eagle Ford, Fayetteville, Haynesville, Marcellus, Niobrara, Wolfcamp (Midland and Delaware Basins), and Woodford.
Using a spatial, statistical approach with key production indicators, we identified key trends across the various basins where the infill wells produced at different production rates compared to their parent wells. Overall, there is about a 50% chance that a child well will outperform a parent well; However, normalizing production to total proppant pumped and lateral length suggests that larger volumes with longer laterals in infill wells may be needed to achieve similar rates to the parent wells.
Underperformance of infill wells may likely be because of existing depletion and inter-well production competition with both parent and other infill wells. Additionally, in areas where significant depletion is expected, predicting the performance of new infill wells can be very difficult. This paper will discuss alternative methodologies and technologies that may help understand and increase the production potential of lower performing infill wells.
Stress changes associated with reservoir depletion are often observed in the field. Stress evolution within and surrounding drainage areas can greatly affect further reservoir developments, such as completion of infill wells and refracturing. Previous studies mainly focus on biwing planar-fracture geometry, which limits the possibility of investigating stress evolution caused by complex-fracture geometry. In this paper, we have developed a novel and efficient coupled fluid-flow/geomechanics model with an embedding-discrete-fracture model (EDFM) to characterize stress evolution associated with depletion in unconventional reservoirs with complex-fracture geometry. Coupled geomechanics/fluid flow was developed using the well-known fixed-stress-split method, which is unconditionally stable and computationally efficient to simulate how stress changes during reservoir depletion. EDFM was coupled to the model to gain capability of simulating complex-fracture geometries using structured grids. The model was validated against the classical Terzaghi (1925) and Mandel (1953) problems. Local grid refinement was used as a benchmark when comparing results from EDFM for fractures with 0 and 45° angles of inclination. After that, the model was used to analyze stress distribution and reorientation in reservoirs with three different fracture geometries: planar-fracture (90° angle of inclination), 60° inclination, and nonplanar-fracture geometries. As the pressure decreases, reservoir stresses tend to change anisotropically depending on depletion area. The principal stress parallel to the initial fracture reduces faster than the orthogonal one as a function of time. The decrease rate of principal stresses is distinct for different shapes of depleted areas created by different fracture geometries. The rectangular shape produced by the planar-fracture geometry yields the largest stress-reorientation area for a variety of differential-stress (DS) values (difference between two horizontal principal stresses). The squared shape produced by nonplanar-fracture geometry yields stress reorientation only for low DS. The results indicate that created fracture geometry has a significant effect on stress distribution and reorientation induced by depletion. To the best of our knowledge, this is the first time a coupled fluid-flow/geomechanics model incorporated with EDFM has been developed to efficiently calculate stress evolution in reservoirs with complex-fracture geometry. Characterization of stress evolution will provide critical guidelines for optimization of completion designs and further reservoir development.
This paper presents results of an experimental study on how fluid viscoelastic properties would influence the particle removal from the sandbed deposited in horizontal annuli. Water and two different viscoelastic fluids were used for bed-erosion experiments. The particle-image-velocimetry (PIV) technique was used to measure the local fluid velocity at the fluid/sandbed interface, allowing for accurate estimation of the fluid-drag forces and the turbulence stresses.
It was found that polymer fluids needed to exert higher level drag forces (than those of water) on the sandbed to start movement of the particles. Results have also shown that, at the critical flow rate of bed erosion, the polymer fluids yielded higher local fluid velocities and turbulent stresses than those of water. Moreover, the local velocity measurements by means of the PIV technique and the resultant bed-shear-stress calculations indicated that enhancing polymer concentration under the constant flow rate should also enhance the drag forces acting on the sandbed. However, these improved fluid hydrodynamic forces did not result in any improvement in the bed erosion. Therefore, the mechanism causing the delay in the bed erosion by polymer additives could not be explained by any decrease in the local fluid velocity and the turbulence.
The primary reason for the delayed bed erosion by the polymer fluids was suggested to be linked to their viscoelastic properties. Two possible mechanisms arising from the elastic properties of the polymer fluids that hinder bed erosion were further discussed in the paper. The stress tensor of the viscoelastic-fluid flow was analyzed to determine the normal stress differences and the resultant normal fluid force acting on the particles at the fluid/sandbed interface. The normal force induced by the normal stress differences of the viscoelastic fluid was identified as one of the possible causes of the delayed bed erosion by these types of fluids.