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The high intensity of hydraulic fracturing in unconventional reservoir has resulted in dramatic increase in water consumption. The reuse of produced water has been driven by both the environmental and economic benefits. The performance of conventional anionic friction reducers is usually affected by the total dissolved solid (TDS) in the water source. We present here a cationic friction reducer which is fully compatible with most of produced water based on results from the lab and field.
A cationic friction reducer was studied in the lab in synthetic brines and produced water from different Basins with TDS up to 275K. Friction reduction was measured at various concentrations of monovalent, divalent and trivalent cations in the brine. The impact of SO42- was also studied as a representative anion. Several field produced water with different level of TDS were also tested to prove the full compatibility. The additional benefit of using this cationic friction reducer is to control the clay swelling demonstrated by CST result. In the field, the cationic friction reducer was successfully applied in the slickwater jobs in North America using 100% produced water, resulting in high pumping rate with low wellhead pressure.
The cationic friction reducer shows excellent friction reduction even in very high TDS. It also exhibits good tolerance to all the cations and anions, most of which usually are problematic for anionic friction reducers. For the jobs performed, the treating pressures were well below the limit at designed pumping rates, and all proppants were placed as planned. The cost saving was significant by using produced water instead of fresh water. The results from the lab and field demonstrate that this cationic friction reducer is a good candidate for wells to be completed with 100% or diluted produced water.
This paper presents a solution to the wells that require or prefer to use produced water in their slickwater jobs. The field data shows that it saves horsepower during operation due to the high friction reduction in produced waters. It also lowers the cost related to produced water disposal and fresh water transportation.
The differences in thermal maturity of migrated, conventional oil vs in situ shale oil can be recognized by standard petroleum geochemical methods. Thermal maturity of the oils was assessed in this study using both gas chromatography (GC) and GC-mass spectrometry (GCMS), often referred to as biomarker analysis.
We present results from a vertical pilot well from the Midland Basin, drilled with water-based mud, which illustrate how to assess the thermal maturity of the oil in rock samples (extracted from cuttings, SWC and conventional core) from the source rock units (notably the Lower Spraberry and Wolfcamp A units here) and the sandstone in the Dean Formation. These results show that the oil in the Dean sandstone is more mature than the in situ shale oil in the Lower Spraberry and Wolfcamp A, and has therefore migrated in to the reservoir at the well location from a deeper, more mature source.
We are also able to recognize the presence of very local oil migration within source rock units into silty layers, which does not result in thermal maturity differences but does cause bulk compositional fractionation, reflected in the SARA data.
We will then use this approach on two produced oils from nearby lateral wells in the Lower Spraberry and Wolfcamp A, to show that they are similar in thermal maturity, whereas the extracted oil from the Lower Spraberry is less mature than the produced oil from the same unit. We infer therefore that the Lower Spraberry produced oil contains a contribution from a more mature source than the in situ oil, and the most likely source for this more mature oil is the underlying Dean sandstone.
Petroleum geochemical methods demonstrate that so-called unconventional source rock, or shale, oils may be a mixture of both conventional migrated oil in sandstone and in situ oil in source rocks, due to the fractures penetrating into the sandstone. This may also help to explain bulk properties, such as API gravity, of the oils.
Production optimization while reducing data acquisition costs is a key factor in successful development of unconventional plays. Completion strategies in such plays typically involve geometrical approaches that ignore subsurface heterogeneities. Cost-effective subsurface data acquisition techniques are needed to design more effective completion strategies and to close the loop through production evaluation of the engineered fractures.
A new formation evaluation technique was performed 1) in the open hole of a horizontal shale gas well and 2) in the cased hole of the same well post fracking. This technique combines the principles of well testing and logging, and all measurements are made at the surface. In an open hole, it provides a continuous injectivity index profile from which better-producing zones can be identified and in which the hydraulic fracturing strategy can be optimized. When running post -fracturation, it provides injectivity of each cluster and enables identification of successfully fracked clusters.
An open hole test was performed with the well still equipped with the drill pipe. A batch of base oil, less viscous than drilling mud, is circulated continuously. The two liquids, base oil and drilling mud, were separated by a viscous spacer. The annulus wellhead pressure was increased to impose an overhead pressure at formation depth. Because the wellbore pressure is almost constant, the difference between the wellhead flow rates at the inlet in the drill pipe and at the outlet in the annulus provides the total injection rate into the formation. This formation injection rate changes as the less-viscous liquid passes through the open hole due to the viscosity contrast between the two liquids. An injectivity profile is derived from the wellhead flow rates.
Two runs were performed in the same open hole complying with HSE drilling rules and without any well integrity issues at the casing shoe. The observed variations in formation injectivity were consistent between the two runs and the injectivity logs showed strong correlations to gamma ray (GR) and mineralogy logs. The 1500-m long lateral section of the open hole was tested in less than 30 minutes, demonstrating the potential of the method to be industrialized at a low cost.
Frac-driven interactions (FDIs), more commonly known as frac hits, are becoming increasingly common as operators develop acreage near existing wells. These FDIs are commonly observed in an area of infill drilling in eastern Reagan County, Texas. To better understand their effects, a study was undertaken to document all FDIs observed during five years of field development in a fifteen-square-mile area. FDI frequency and intensity was found to be a function of (a) the parent well’s wellbore geometry, (b) offset direction between the parent and child well, (c) the presence or absence of a horizontal “buffer” well, and (d) distance between the parent and child wells. Horizontal parent wells received FDIs with greater frequency and intensity than vertical parent wells. Similarly, vertically stacked or directly offset parent wells received FDIs with greater frequency and intensity than indirectly offset or horizontally in-line parent wells. Horizontal parent wells commonly attenuate (or “buffer”) FDI frequency and intensity for other parent wells behind them (relative to the frac job). Distance between the parent and child well was found to have a strong negative correlation with FDI frequency and intensity but is more pronounced for vertical parent wells than horizontal parent wells. The majority of parent wells were found to receive either small FDIs or no FDI at all; thus, FDIs do not appear to pose a major risk to reserves within the study area contrary to many other unconventional plays. Although simple, the methodology was found to be a useful tool for understanding complex relationships between parent and child wells and may be applied to other development areas.
Multistage hydraulically fractured horizontal well completions have come a long way in the last two decades. Much of this advancement can be attributed to the shale gas revolution, from which numerous transformational tools, techniques, and concepts have led to the efficient development of ultralow-permeability resources on a massive scale. Part of this achievement has been through a widespread trial and error approach, with the higher risk/failure tolerance that is a trademark of the statistical nature of the North American unconventional resource business. However, careful consideration must be taken not to blindly apply these techniques in more permeable tight gas formations, which often cover an extensive range of permeability. Inappropriate application can compromise the effectiveness of the hydraulic fracture treatment and impair long-term well productivity.
Khazzan is a tight to low-end conventional gas field in the Sultanate of Oman, with low porosity and permeability in comparison to conventional formations. The target formations comprise extremely hard, highly stressed rocks at high temperature. The development strategy included vertical wells with massive hydraulic fracture treatments and multistage fractured horizontal wells. The former has been largely successful in the higher-permeability areas, and the economic transition from vertical to horizontal well development, based on rock quality, is continuously evolving. Compared to the rapid learning curve achieved through the more than 80 vertical wells drilled to date, fewer horizontal wells have been drilled, and, as a result, the understanding is still relatively immature.
The paper outlines the technical and operational journey experienced in horizontal wells, to prepare the wellbore and ensure a suitable frac/well connection for successful fracturing and well testing. The paper will describe how the intervention tools and practices have varied between the Barik and Amin formations; depending upon rock quality, frac treatment type, drive to maximize operational efficiency and availability of local resources. The differential application of these techniques, that result in measurable under-flush versus in contrast to the typical North American unconventional practice of defined but limited overflush (e.g., pump-down plug-and-perf will be described). Justification for these different approaches in two very different formations will be demonstrated, including supporting evidence of their relative value.
The obstacles that have been faced, overcome and are still ongoing with this campaign highlight the importance of several critical factors: including multi-disciplinary integration and planning, wellbore construction impacts, contractor performance and tool reliability. Although practices for shale and very low permeability sands are well documented, this paper provides a suite of case histories and operational results for horizontal well intervention techniques used in high-pressure and high-temperature sandstones that are in the very specialized transition zone between conventional and unconventional.
Padin, Anton (Total Exploration and Production) | Pijaudier-Cabot, Gilles (Université de Pau et des Pays de l'Adour) | Lejay, Alain (Total Exploration and Production) | Pourpak, Hamid (Total Exploration and Production) | Mathieu, Jean-Philippe (Total Exploration and Production) | Onaisi, Atef (Total Exploration and Production) | Boitnott, Gregory (New England Research, Inc.) | Louis, Laurent (New England Research, Inc.)
Having a large number of layers in a reservoir model is computationally time-consuming, hence simulation of hydraulic fracturing in unconventional reservoirs usually rely on simplified, log-based models. In such models, vertical heterogeneities are upscaled to a few, averaged facies with homogeneous stiffness, stress, strength, toughness and natural fracture properties. In reality, however, unconventional reservoirs often contain singular heterogeneities and strong vertical and horizontal anisotropic properties that greatly affect fracture growth. The abundance of heterogeneities is believed to affect vertical hydraulic fracture growth (positively or negatively) due to stress differences, toughening effects at interfaces or the piling of thin lithologies with extreme, opposed stiffness or strength properties. From the simulation point of view, the challenge remains keeping a computationally-efficient but also representative (well-upscaled) model.
In this work, we focused on stiffness characterization, and particularly, on Young’s modulus calibration, and provide a concept-proof example for the Vaca Muerta formation, in Argentina. The current strategy in building stiffness models is to rely on sonic data to generate upscaled models with a few representative layers. A core acquisition program is normally put in place to calibrate the log-based model, and includes triaxial tests, where dynamic and static properties are measured at various stress conditions. Technically, characterization of each relevant lithology using these core measurements is possible, but given the degree of vertical heterogeneity, it would imply a very important logistical and economical effort. In addition, core plug selection is usually biased towards the stiffest rocks, leaving aside other facies, such as weak or ductile layers. As a result of these difficulties, core programs are usually limited to a few core plugs covering the target reservoir, leaving calibration of other units, and particularly of potential fracture barriers, unknown.
To address these difficulties, we concept-proved a core-to-log methodology that provides a fast calibration method for log-based elasticity. We measured rebound hardness in parallel to dynamic measurements of ultrasonic surface wave velocities (P and S) at the milimetric scale, then calibrated the results with discrete triaxial tests performed on plugs, representing all relevant lithological facies, and finally compared the results against log-based parameters. Our work shows that such integration helps at developing robust core-to-log elasticity relationships in the entire core length, eventually providing a proper foundation for better stiffness model prediction, at a fraction of the cost and time of traditional core acquisition programs.
Dong, Xiaohu (China University of Petroleum Beijing) | Liu, Huiqing (China University of Petroleum Beijing) | Wu, Keliu (China University of Petroleum Beijing) | Liu, Yishan (China University of Petroleum Beijing) | Qiao, Jiaji (China University of Petroleum Beijing) | Gao, Yanling (China University of Petroleum Beijing) | Chen, Zhangxin (University of Calgary)
The presence of nanopores in tight and shale rocks has been confirmed by numerous studies. Due to the pore-proximity effect, the confined behavior of fluids in nanopores differs significantly from that observed in PVT cell. Currently CO2 huff-and-puff has been used to unlock the tight and shale reservoirs. Because of the high adsorption selectivity of CO2, after the injection of CO2, the original fluid density and composition of hydrocarbons in nanopores has been changed. In this paper, the PR-SLD model is applied to investigate the confined behavior of pure CO2/hydrocarbon fluids and their mixtures in nanopores. The Lee’s partially integrated 10-4 potential model is used to represent the solid-fluid interaction. For mixtures, a group contribution method is used to estimate the binary interaction parameters of CO2/hydrocarbon mixture. Thereafter, from the results of density distribution across the nanopore, the adsorption amount of fluids can be derived. Based on this model, a prediction process for the behavior of pure CO2 and hydrocarbon fluids (of methane and ethane) and their mixtures is performed. Results indicate that the adsorption selectivity of CO2 is much higher than CH4 and C2H6. And the density of pure CO2 in nanopores is higher than that of CH4 and C2H6. For binary mixture, because of the difference of interaction energy, the mole fraction of CO2 molecular is gradually increased from pore center to pore surface, and that of the hydrocarbon molecular is reduced from pore center to pore surface. The composition difference between bulk fluids and adsorbed fluids of CO2-C2H6 mixture is lower than that of CO2-CH4 mixture. For ternary mixture, the mole fractions of CO2 and C2H6 are always increasing from pore center to pore surface, and the mole fraction of CH4 is decreased from pore center to pore surface. Compared the original pure hydrocarbon mixtures, the addition of CO2 further increases the density of bulk fluids and adsorbed fluids. This study sheds some important insights for the behavior of confined fluids in nanopores and provides sound guidelines for the application of CO2 huff and puff in tight and shale reservoirs.
A study analyzing a method to detect the leak quantity and its location through computational modeling is presented. Specifically, there is a focus on the transportation of wet natural gas, or methane with a mixture of condensates. Pipeline inclination was an important component of the study as the model considered a pipeline constructed within hilly terrain. Analysis was performed for wet gas pipelines through transient simulations in the OLGA software suite.
Several scenarios were modeled for this study: baseline cases at different operating pressures with no leak, cases with leaks modeled in downhill pipe segments, and cases with leaks modeled in uphill pipe segments. The leaks were modeled with identical characteristics for the two latter cases and were relatively small. It was determined that leak detection is possible in OLGA when trends in certain parameters are monitored. For this study, the minor and moderate leaks were seemingly undetectable using pressure but were detectable using trends in volumetric flow rates at locations upstream and downstream of the leak, and at the pipeline outlet. In addition, the magnitudes of fluctuations in flow parameters were increased significantly at higher pipeline pressures. The severe leak cases were detectable using all parameters.
Pipelines are the safest and most economical method for transporting oil and gas across long distances. In order to maintain a high level of safety, leak detection is an important part of daily operations. There are two primary methods of identifying a leak in a petroleum pipeline: through direct assessment or physical inspection (non-continuous method) and model simulation (continuous method).
The United States Department of Transportation (DOT) requires that physical inspections are performed by the operator on a set frequency based on risk assessments and other factors. Despite the regulation requirements, physical inspections can have a negative impact on pipeline economics by creating a need to take segments offline and allocate resources to the work. However, a computer simulation allows the operator to analyze potential leak scenarios and compare them to current pipeline performance while remaining online. The key disadvantages to simulations include the need for prior regulatory approval, and a lack of adequate information for assessing the integrity of the pipeline without concurrent use of other tools. It is worth noting that this study is focused on the continuous leak detection method but does not disregard the regulatory requirement for performing direct assessment. There are various types of leak detection systems (LDS) that are often used concurrently. A brief overview of these non-continuous and continuous LDS will be discussed.
Dande, Suresh (University of Houston / Sigma Cubed Inc.) | Stewart, Robert R. (University of Houston) | Myers, Michael T. (University of Houston) | Hathon, Lori (University of Houston) | Dyaur, Nikolay (University of Houston)
In a hydraulically fractured reservoir, estimating propped reservoir volume is key to predict production. In this study, we use various samples, including 3D-printed models with air-filled plus sand and ceramic proppant-filled fractures, as well as Eagle Ford Shale samples with artificially created fractures with air and sand-proppant. From the 3D-printed model in uniaxial compression experiments, we found that Vs is decreased by 10% for the sand-proppant model, and the Young’s modulus of sand-propped models are lower than the air-filled or unpropped models, suggesting that propped models may be more compliant. Normal compliance calculated from the static data confirms that propped models are more compliant. We extend this experiment with Eagle Ford Shale samples, we find that S-wave velocity is faster in propped rock in all directions (00, 450, 900 to the bedding). We also observe that Vp normal to the bedding direction is faster in propped rock than in unpropped rock. The increase in shear velocity could be attributed to the addition of faster material(sand) to the saw cuts. Though we are looking at the same problem, the different results between 3D printed and Eagle Ford shale may be real as the materials are different and experiment procedures are different.
Fiber optic cables deployed within or outside wellbore casing provide opportunities to record orders of magnitude more borehole seismic data than has been economically feasible with traditional 3-component borehole seismic geophones. The recording method, known as DAS (Distributed Acoustic Sensing) provides seismic information at a “receiver” spacing of typically 3 to 15 ft over the entire length of the fiber optic cable. A DAS cable deployed in a well that has a depth of 10,000 ft and a 10,000 ft horizontal section will provide thousands of separate seismic data channels, all recorded simultaneously, and with a receiver spacing that is typically reserved for very shallow near-surface seismic surveys (3-15 ft).
In spite of the viability of DAS seismic recording being a relatively recent event, the technology has been successfully used in multiple seismic disciplines. Zero-offset, 2D and 3D VSP surveys have been successfully recorded, microseismic data is commonly recorded on DAS cables, and active surface seismic sources recorded on the horizontal part of the DAS cable all provide high quality and useful P-wave and S-wave data.
The purpose of this paper is to present results from a DAS microseismic seismic survey and from a time-lapse seismic reflection imaging survey, both recorded on the same two DAS cables in separate wells. The seismic reflection imaging part of the paper is presented first to introduce a new method of seismic reflection imaging using DAS seismic data. The methodology that leads to successful processing of the active seismic source data is then extended to using microseismic events as seismic sources, thus yielding S-wave reflection images with 40-ft vertical resolution. Finally, microseismic data showing reflections from transient fractures that open and close during hydraulic fracture stimulation of an adjacent well provides highly accurate fracture locations that intersect the horizontal wellbore containing the DAS cable.
Fundamentals of DAS Recording
Figure 1 is a sketch that shows a well that turns horizontal at some depth and which we assume has a DAS cable temporarily deployed within the casing or permanently deployed on the outside of casing. A surface seismic source is represented by a photo of a Vibroseis truck though any seismic source can be used for DAS recording including dynamite or other impulsive source. The figure indicates that laser light is shone down one of the fibers. Impurities in the fiber tend to generate reflections that travel back up the fiber in the opposite direction of the “downgoing” laser light. Since the distance between the impurities is fixed, the changing interference patterns between the reflected light is used an electronic system at the surface called an Interrogator to determine the strain rate along the long axis of the DAS fiber. The interrogator divides the DAS cable into segments of between typically 3 and 15 ft for measurement of strain rate and outputs those strain rate measurements as seismic data.