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Recent advances in drilling and oil & gas extraction have altered the mindset among drilling engineers. One example is the recent trend to drill faster and minimize Non-Productive Time (NPT). This usually requires minimizing changes to the Bottom Hole Assembly (BHA) and improving its reliability. Directional drilling tools such as mud motors and Rotary Steerable Systems (RSS) have become a main stay in minimizing NPT. Moreover, understanding in planning stages the tools’ working envelope in downhole environment, is critical to reducing NPT. Conventional surface testing, however, have significant constraints when trying to determine the performance envelope of directional tools and BHAs.

Advances in numerical modeling enable evaluation of BHA performance under much more realistic downhole conditions. This paper discusses the advancements in the evaluation of directional drilling tools using advanced Time Domain Analysis (TDA). For example, time domain models allow exploration of the full range of BHA response under downhole conditions including the effects of formation changes. Drilling dysfunctions including stick-slip, whirl, and dynamic lateral vibrations can be realistically predicted before drilling. TDA models allow drilling engineers to explore the design space and also explore operating conditions to optimize performance and reliability of the BHAs.

This work describes a newly implemented TDA model based on rigid body dynamics (RBD) solved by finite element methods (FEM) to model drilling dysfunctions. The approach is significantly more accurate and faster compared to conventional models. Also shown is how the TDA model successfully predicted several drilling dysfunctions before drilling and reduced NPT. It is also used to analyze post drilling job cases and explain issues observed in the field.

Liquids-rich gas plays present significant challenges to producers to keep wells flowing and maximize production. In particular, liquid loading is a frequent issue as production rates decline and flow rates are no longer sufficient to keep liquids entrained in the gas stream. Many strategies exist and have been attempted over the years for attempting to keep these wells flowing and avoid liquid loading.

Perhaps the most attractive option is wellhead compression, which will lower wellhead pressures and increase flowrates, both items necessary to eliminate liquid loading. By reducing wellhead pressures, compressors will also increase the recoverable assets of a well. Traditional compression is not able to operate with liquids present and thus requires additional infrastructure and facilities to separate, store, and transport the liquids. Multiphase production facilities are a good solution to eliminate the need for additional infrastructure at the wellhead, and instead move the multiphase flow downstream to a central facility for processing. However, the more common multiphase pump technologies suffer from low efficiencies in the high gas volume fraction (GVF) conditions typical in liquids-rich gas wells.

A new multiphase compression technology is identified with the potential to achieve the benefits of multiphase production while operating at efficiencies closer to a traditional compressor. Testing is conducted with the new technology on several different wet gas wells in the Eagle Ford. Testing shows that the compressor is successfully able to handle a multiphase stream coming directly from the well without any additional separation facilities. Additional testing further demonstrates that the compressor may even be able to unload a well that is already loaded.

Further testing and development work will be required to broaden the conditions at which the compressor can operate and to prove that it can successfully maintain a variety of different wells flowing above their critical rates and unloaded. Initial indications are very promising and suggest that the new compressor technology will be a powerful tool for producers to use in maximizing the production of liquids-rich wells.

Plunger lift is a popular low operating and capital cost lift method for high gas-liquid ratio (GLR) wells that cannot unload naturally, particularly in deep, liquids-rich gas, horizontal plays common today. Plunger lift is challenged by lengthy plunger travel time, greatly increased GLR requirements, and liquid loading effects in the build section of the well.

This paper explores the implementation of an artificial lift technology designed to enhance the performance of artificial lifts systems and for cost-effective artificial lift transitions over the life of a well. It will extrapolate upon the challenges associated with developing a total life-cycle artificial lift strategy for today's unconventional plays in the Permian Basin.

Discussion begins with an overview of the theoretical challenges of designing a life cycle artificial lift strategy with a conventional system in the face of sluggy flow and high decline rates from the horizontal. The paper then proposes an artificial lift approach to suit this challenge.

The paper then presents an overview of plunger lift optimization challenges experienced in horizontal well production strategy from frac-flowback to abandonment. It explores the characteristics unique to plunger lift and demonstrates the connection between slug flow mitigation and improved plunger lift efficiency. The result is a discussion of a new, slickline swappable, artificial lift technology for plunger lift systems that mitigates slug flow, thereby enabling efficient plunger lifting at considerably lower GLRs, through the life of the well.

Case studies and field trials in the Permian field illustrate implementation and results of the artificial lift technology to cost effectively transition from natural flow to plunger lift and on to rod pumping, with optionality to provide low cost and safe frac-hit protection from offsetting wells. Results demonstrate production increases with reduced CAPEX and OPEX.

Like many unconventional plays, the Eagle Ford, once one of the most active shale plays in the world with over 250 rigs running, saw a vast amount of data collected during the boom over a very short time. As with most unconventional resources, a lack of validation of reservoir parameters prevailed in the early history of these plays (emerging plays) and thus, hypothesis drove drilling and completion optimization programs. The 2015 drop in commodity prices accelerated the need to optimize well designs and spacing and stacking patterns in a less capital-intensive manner. A sector model was built that enabled discrete modeling of the 4 development wells in place and significant remaining undeveloped potential to be completed both within and near the sector model area. From this model, substantial understanding around the key parameters driving subsurface performance both from the rock and wellbore design perspectives was gained. As in-fill drilling has occurred in other areas of the play, a learning curve developed around the understanding of vertical connectivity, fracture geometry, well interference and the impact of clusters and job size on fracture contact with the reservoir. This learning curve has been applied to the integrated model to understand what an optimized infill drilling program for the area would look like at various hydrocarbon pricing scenarios.

This paper utilizes an integrated model approach to understand reservoir performance on a pad with four wells completed across multiple horizons in the Eagle Ford. Wireline quad combo compressional and shear log suites (including azimuthal anisotropy and VTI sonic processing, resitivity/acoustic borehole imagers, and NMR), core (geomechanical, geochemical analysis, routine core analysis and specialized core analysis), completion data (fracture treatments with pre-and post-job shut-in pressures), production data (1200 days of production history with a bottom-hole pressure gauge and calculated bottom hole pressures from rod pumps) are used to build petrophysical models, geo-models, geomechanical models, fracture propagation models and reservoir models with the aim of understanding completion and production drivers. A workflow is presented that enables these models to improve our understanding of layering effects (vertical connectivity), fracture asymmetry (pressure sinks or sources), well interference (hydraulic vs. propped lengths) and the impact of clusters and job size on fracture contact with the reservoir.

Model developments for transient analysis of fractured horizontal wells have gained tremendous attention in tight reservoirs, especially, during the flowback period. However, the existing models so far have rarely considered two-phase flow and complex fracture networks. To improve this situation, in this work, we present a new semianalytical two-phase flow model. Water and oil simultaneously flow in the matrix and fracture networks. By iteratively correcting the relative permeability to water and gas phases, we incorporate the two-phase flow into fracture model. Complex fracture networks with arbitrary geometries are described and the fluid flow interplays at fracture intersections are eliminated through mass balance equation. The model solution is obtained by using Laplace transform inversion, and it is verified by performing a case study with a numerical simulator. Our results show that there exist two distinct flow regimes: fluid feed and pseudo-boundary dominated flow (PBDF), which is generated by the permeability contrast between fracture networks and matrix. We also investigate the impacts of some key reservoir and fracture properties on the characteristics of productivity index. Results indicate that the productivity index increases with an increase in initial water saturation. Furthermore, it is found that during the PBDF, different fracture-network parameters have various constant productivity indexes, providing an efficient tool to characterize the fracture networks. Based on that, we apply the model to estimate the fracture networks of a tight-oil well in CJ formation at Tarim Bain with flowback data and micro seismic data, which provides an efficient technique to estimate the stimulation effectiveness during the flowback period.

Hydrogen and helium detection can benefit drilling operations when combined with methane-through-pentane gas chromatography. The addition of hydrogen and helium analysis to surface detection can lead to lower-cost wells and possibly increased production.

In the oil industry, hydrogen has five sources, three of which are geological and two are manmade. The geological sources are basement rock, fractures, and liquid hydrocarbons, and the manmade sources are drill bit metamorphism (DBM) and mud motor failure. Helium has two geological sources—basement rock and faults. When hydrogen and helium detection are combined with gas chromatography, the source of the hydrogen and helium increases can be determined.

During geological analysis, hydrogen and helium spikes, where helium is present in much higher concentrations, without the presence of ethane, are indicative that a fault has been encountered. Porosity and/or permeability increases indicate a sustained increase in hydrogen and helium with an increase in methane. When liquid hydrocarbons are present, increased hydrogen concentrations with methane are detected, and the increase in hydrogen relative to helium is significant. Where drilling applications result in DBM and mud motor failure, hydrogen increases without a corresponding increase in methane or helium. Ethane and propane concentrations also increase with hydrogen during these events. Using this knowledge, changes in reservoir properties can be determined without relying on costly downhole tools while drilling. In addition, this information can be used in extended reach wells to identify faults and help geosteer the well. From a drilling perspective, such information provides confidence regarding identification of mud motor failure and bit drilling efficiently to help prevent costly bit trips.

Hydrogen and helium detection provides a low-cost alternative to costly downhole tools for providing real-time detection of faults, drilling inefficiencies, and relative porosity and permeability. This technology also provides a low-cost solution for well placement.

The stress state at infill wells changes as a function of production from the existing producer. Understanding spatial and temporal in situ stress changes surrounding drilled uncompleted (DUC) wells or infill wells has become increasingly important as the industry works through its inventory of DUC wells and redesigns infill wells with an engineering approach.

Optimizing infill/DUC well completion designs requires an estimation of the altered in situ stress state. This study presents the concept of a "production shadow" as the stress change in four-dimensional space, affecting well performance and optimal well configurations for pad development. The production shadow accounts for the compound effects from both hydraulic fracture mechanical opening and stress-state alteration from depletion.

This paper details an Eagle Ford case study integrating production shadow effects into the parent and infill well hydraulic fracture modeling as well as "frac hit" analysis. The production shadow influences the degree of fracture complexity developed by the infill/DUC well stimulation. Understanding and accounting for the production shadow are critical in engineering to establish and preserve an optimal connection of the induced stimulated fracture network to the wellbore.

One of the most important hydrocarbon resources in the Western Canadian Sedimentary Basin (WCSB) is the Montney tight shale formation, which extends approximately 55,000 square miles from northeast British Columbia to northwest Alberta. Operations in the Alberta deep-basin Montney have proven this area to be one of the continent's most productive unconventional resource plays. As part of the field development plans, cores are cut from the reservoir rock to directly measure source rock properties through analysis of core samples and calibrating wireline logs with data extracted from the core samples.

The subsurface geology of the upper hole section in this particular area is complex, where reactive, swelling, and fissile shale as well as coal beds and lost-circulation zones extend across 2700 m of the openhole section. As such, historically in this field, the Montney has been cored using a weighted oil base system incorporating water contamination into the core; if zero water contamination is mandated, casing is run into the reservoir ahead of the coring section to allow coring with base oil, which leads to smaller core sizes. Additionally, coring operations can require several days when conventional coring technology is applied because of the multitude of necessary trips into and out of the hole.

Well engineers applied a systematic approach to achieve new targets by incorporating the latest available technologies and drilling techniques in the industry into a coring program while also optimizing well structural designs by minimizing use of casing strings. This allowed achieving the project's primary objectives of cutting larger-sized cores with no water contamination using minimal planned trips.

This paper discusses how managed pressure drilling (MPD) and wellbore strengthening techniques, as well as new coring technologies, were analyzed, planned, and incorporated into this project. This led to the successful execution of an optimized, cost-efficient well structural design with 100% core recovery and no water contamination while. At the same time, a new record was set in terms of the longest core length cut in one run in onshore North America.

Experimental and numerical studies have demonstrated that there is great potential of enhancing the oil recovery from tight formations. This study investigated the effect of acid matrix treatment by applying gas flooding on the core samples before and after the treatment. The aim of the acid stimulation treatment was to improve the low-permeability of the cores.

Four core samples (0.5 in, 1.0 in, 1.5 in, and 2.0 in) from an outcrop of the Eagle Ford formation were used in this study. Permeability was measured before and after the acid treatment. The cores were CT-scanned to identify natural fractures. Different gas injection pressures were used to study the oil recovery and the time needed to penetrate through core samples. Furthermore, a solubility test was applied to identify the optimal acid concentration. The cores were re-scanned after the acid flooding treatments to detect any change. Gas flooding was applied to acidized core samples to detect changes in penetration time and recovery factor.

A solubility test demonstrated that 15% of HCL was the optimal acid concentration for the Eagle Ford formation. The study showed the porosity, permeability, recovery factor, and penetration time before and after the acidizing treatment. Permeability was enhanced from 1.04 nanodarcies to 2.10 microdarcies. Furthermore, the study showed the effect of core length on penetration rate (in/min) of gas flooding and the recovery factor at each injecting pressure. The penetration time in this study varied from 207 to 112 minutes/inch when the injecting pressure increased from 1500 to 2500 psi. After acidizing, however, the penetration rate decreased to 8.4 minutes/inch using flooding of 300 psi. The CT scan showed improvement of the micro fracture width.

Ignoring the presence of pyrite can lead to errors in the estimation of Total Organic Carbon (TOC) since pyrite has significantly higher density and conductivity compared to other minerals in shale formations. This study aims to improve the accuracy of estimating TOC from well log data by accounting for the pyrite effect in Eagle Ford shale. To this end, more than 50 feet of preserved cores samples from the Eagle Ford were analyzed using laboratory pyrolysis, X-ray fluorescence (XRF), X-Ray Diffraction (XRD), and spectral core gamma system.

Since there is significant vertical heterogeneity in the Eagle Ford shale, parameters such as TOC, pyrite content, Gamma ray intensity, content of Fe and S, and concentrations of U, Th, and K were analyzed on a fine scale in the Upper and Lower Eagle Ford respectively. Analysis of laboratory TOC data were applied to calibrate TOC data using geophysical well logs methodologies. Pyrite data from XRD analysis were used to find the relationship between pyrite and organic matter and to determine the effect of pyrite on well logs. Well-log-based TOC calculation methods were improved by considering pyrite as an adjustable parameter in equations. Schmoker's (1983) four-component system rock model and Alfred and Vernik's (2013) two-pore system model are two representatives of density-log-based TOC calculation methods. Based on these two models, a new petrophysical model considering pyrite and organic porosity was developed.

In this research, empirical correlation between TOC and pyrite was explored. Changes of Fe and S concentrations with depth and Gamma ray intensity was determined. The trends of Fe sand S contents matched Gamma ray intensity very well in the depth range from 13790 ft to 13825 ft. Empirical relationships were found between TOC and Gamma ray intensity, TOC and Uranium, respectively. Furthermore, a new petrophysical model considering pyrite and organic porosity was validated with TOC and density data from shale formations. The proposed model improves the estimation of TOC calculation in Eagle Ford formation by the incorporation of pyrite effect.