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As the industry shifts from a high number of short-length wells to fewer, but longer lateral wells, the stakes are raised for operators as bigger does not always mean better and economies of scale are reduced. This article describes how the application of optically derived, in-situ measurements enables completion engineers to optimize the design and execution of frac operations and successfully reap the rewards of quality over quantity. The success of unconventional resources has changed the landscape of energy production globally. However, owing to the fundamental need to fracture otherwise impermeable formations and the inherently short productive life of frac wells, the economics of unconventional resources remains a capex intensive challenge. Operators are seeking the cost savings of reduced well counts, whilst achieving the same production with lower environmental impact.
Recently, global climate change and air quality have become increasingly important environmental concerns. Consequently, there has been a rise in collaborative international efforts to reduce the concentration of greenhouse gases and criteria pollutants. Greenhouse gases include carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O), occurring naturally and as the result of human activity. In addition, criteria pollutants (1970 amendments to the Clean Air Act required EPA to set National Ambient Air Quality Standards for certain pollutants known to be hazardous to human health) include emissions of nitrogen oxide, sulfur dioxide, carbon monoxide, and total unburned hydrocarbons. International and national governments are implementing more regulations on air emissions.
Independence Energy and Contango Oil & Gas announced today an all-stock merger that will create a company with an estimated enterprise value of almost $5.7 billion. Independence shareholders will own 76% of the combined company which is to be headquartered in Houston. Contango shareholders will own the remainder. The two companies combined production for the first quarter was approximately 111,000 BOE/D and their combined decline rate for the year is estimated to be 18%. On a pro forma basis, the 2020 booked reserves show a commodity breakdown of 47% oil, 15% natural gas liquids, and 38% natural gas.
Abstract A new, through-the-bit, ultra-slim wireline borehole-imaging tool for use in oil-based mud provides photorealistic images. The imager is designed to be conveyed through drill-pipe. At the desired well section, it exits the drill pipe through a portal drill bit and starts the logging. Field test measurements in several horizontal, unconventional wells in North America show images of fine detail with a large amount of geological information and high value for well development. A relatively new solution for conveying tools to the deepest point of a high angle or horizontal wells uses a drill bit with a portal hole at the bit face. As soon as the bit reaches the total depth, a string of logging tools is pumped down through the drill pipe. The tools exit the bit through the portal hole, arriving in the open hole and are ready for the up log. The tools operate on battery and store the log data in memory so that no cable is interfering as the drill pipe is tripped out of the well while the tools are acquiring data. The quality of wireline electrical borehole images in wells drilled with oil-based mud has significantly improved in recent years. Modern microresistivity imagers operate in the megahertz-frequency range, radiating the electromagnetic signal through the non-conductive mud column. A composite processing scheme produces high-resolution impedivity images. The new, ultra-slim borehole-imager tool uses these measurement principles and processing methods. Innovating beyond the existing tool designs the tool is now re-engineered to dimensions sufficiently slim to fit through drill pipes and to use through-the-bit logging techniques. The new, ultra-slim tool geometry proves highly reliable and, due to the deployment technique, highly effective in challenging hole conditions. The tool did not suffer any damage and showed only minute wear over more than twenty field test wells. The tool’s twelve-pad geometry provides 75% coverage in a six-inch diameter borehole and its image quality compares very well with existing larger tools. The field test of this borehole imaging tool covers all scenarios from vertical to deviated and to long-reach, horizontal wells. Geological structures, sedimentary heterogeneities, faults and fractures are imaged with detail matching benchmark wireline images. The interpretation answers allow operators of unconventional reservoirs to employ intelligent stimulation strategies based on geological reality and effective well development. A new high-frequency borehole imager for wells drilled with oil-based mud is introduced. Deployed through the drill pipe and its portal bit, the imager carries photorealistic microresistivity images into wells where conventional wireline conveyance techniques reach their limits in both practicality and viability.
Degenhardt, John J. (W. D. Von Gonten Laboratories) | Ali, Safdar (W. D. Von Gonten Laboratories) | Ali, Mansoor (W. D. Von Gonten Laboratories) | Chin, Brian (W. D. Von Gonten Laboratories) | Von Gonten, W. D. (W. D. Von Gonten Laboratories) | Peavey, Eric (Shell Fellow-UROC / Texas A&M University)
Abstract Many unconventional reservoirs exhibit a high level of vertical heterogeneity in terms of petrophysical and geo-mechanical properties. These properties often change on the scale of centimeters across rock types or bedding, and thus cannot be accurately measured by low-resolution petrophysical logs. Nonetheless, the distribution of these properties within a flow unit can significantly impact targeting, stimulation and production. In unconventional resource plays such as the Austin Chalk and Eagle Ford shale in south Texas, ash layers are the primary source of vertical heterogeneity throughout the reservoir. The ash layers tend to vary considerably in distribution, thickness and composition, but generally have the potential to significantly impact the economic recovery of hydrocarbons by closure of hydraulic fracture conduits via viscous creep and pinch-off. The identification and characterization of ash layers can be a time-consuming process that leads to wide variations in the interpretations that are made with regard to their presence and potential impact. We seek to use machine learning (ML) techniques to facilitate rapid and more consistent identification of ash layers and other pertinent geologic lithofacies. This paper involves high-resolution laboratory measurements of geophysical properties over whole core and analysis of such data using machine-learning techniques to build novel high-resolution facies models that can be used to make statistically meaningful predictions of facies characteristics in proximally remote wells where core or other physical is not available. Multiple core wells in the Austin Chalk/Eagle Ford shale play in Dimmitt County, Texas, USA were evaluated. Drill core was scanned at high sample rates (1 mm to 1 inch) using specialized equipment to acquire continuous high resolution petrophysical logs and the general modeling workflow involved pre-processing of high frequency sample rate data and classification training using feature selection and hyperparameter estimation. Evaluation of the resulting training classifiers using Receiver Operating Characteristics (ROC) determined that the blind test ROC result for ash layers was lower than those of the better constrained carbonate and high organic mudstone/wackestone data sets. From this it can be concluded that additional consideration must be given to the set of variables that govern the petrophysical and mechanical properties of ash layers prior to developing it as a classifier. Variability among ash layers is controlled by geologic factors that essentially change their compositional makeup, and consequently, their fundamental rock properties. As such, some proportion of them are likely to be misidentified as high clay mudstone/wackestone classifiers. Further refinement of such ash layer compositional variables is expected to improve ROC results for ash layers significantly.
Abstract A new 2 1/8-in. outer-diameter photorealistic imager for oil-based muds (OBM) has recently started field testing in unconventional formations in North America. To obtain the best interpretation of its measurements, a twostep quantitative inversion workflow has been developed with a performance similar to the existing inversion workflows for the regular high-definition OBM imagers. The new inversion workflow provides borehole resistivity images, borehole rugosity images, and borehole dielectric permittivity images as well as multiple quality curves. The modeling of the new borehole imager is performed with a 2D axisymmetric finite element code. An efficient forward model is developed by fitting the tool response tables into fourth-order polynomials in terms of the sensor standoff, formation, and mud impedivities for broad ranges of model parameters. The fast forward model based on the polynomial fitting is calibrated against the actual tool measurements in a laboratory setup and applied in the inversion algorithms. The inversion workflow is tested with synthetic data and the inverted model parameters are compared with their true values to study and analyze their corresponding measurement sensitivity and optimize the inversion input parameters. It is used to invert several field test datasets in unconventional wells. The results show that the inversion results provide critical added value for formation evaluation, showing geological features that would otherwise be missed, such as fracture properties. Projection-based formation impedivity images, as available for the regular high-definition OBM imagers, are ideal for conductive formations but suffer from a rollover effect in resistive formations. In comparison, the image formed from the inverted formation resistivity does not roll over and is more consistent for resistive formations. The image formed by the inverted standoff reflects surface conditions of the borehole and can be used to interpret whether the fractures and the faults are open, closed, or damaged in the drilling process. Multiple image examples are given from unconventional wells to demonstrate that the inverted standoff image can reveal fractures when there is insufficient or even no contrast in medium properties. The inverted standoff image also serves as a diagnostic tool for interpreting borehole and tool conditions during the measurements. The inverted permittivity may have a larger dynamic range than the resistivity especially for unconventional formations, thus providing an alternative and potentially clearer borehole image.
Johnson, Andrew C. (Schlumberger) | Miles, Jeffrey (Schlumberger) | Mosse, Laurent (Schlumberger) | Laronga, Robert (Schlumberger) | Lujan, Violeta (Schlumberger) | Aryal, Niranjan (Schlumberger) | Nwosu, Dozie (Schlumberger)
Abstract Formation water saturation is a critical target property for any comprehensive well log analysis program. Most techniques for computing saturation depend heavily on an analyst’s ability to accurately model resistivity measurements for the effects of formation water resistivity and rock texture. However, the pre-requisite knowledge of formation water properties, particularly salinity, is often either unknown, varying with depth or lateral extent, or is difficult to derive from traditional methods. A high degree of variability may be present due to fluid migration from production, water injection, or various geological mechanisms. In unconventional reservoirs, the complexity of the rocks and pore structure further complicates traditional interpretation of the available well logs. These factors introduce significant uncertainties in the computed fluid saturations and therefore can substantially affect final reserves estimates. A novel technique in geochemical spectroscopy has recently been introduced to distinguish the chlorine signals of the formation and borehole. The new, quantitative measurement of formation chlorine enables a direct calculation of bulk water volume for a given formation water salinity. When integrated into a multi-physics log analysis workflow, the chlorine-derived water volume can provide critical information on fluid saturations, hydrocarbon-in-place, and producibility indicators. This additional information is especially useful for characterizing challenging and complex unconventional reservoirs. We present the new technique through several full petrophysical evaluation case studies in organic shale formations across the U.S., including the Midland, Delaware, Marcellus, and DJ basins. We solve for formation-specific water salinity and bulk water volume through an optimization that combines chlorine concentration with resistivity and dielectric measurements. These outputs are integrated into comprehensive petrophysical evaluations, leveraging a suite of advanced well log measurements to compute final fluid and rock properties and volumetrics. The evaluations include geochemical mineralogy logs, 2D NMR analyses, dielectric dispersion analyses, basic log measurements, and multi-mineral models. The results underscore the utility of the new spectroscopy chlorine log to reduce petrophysical model uncertainties in an integrated workflow. While this workflow has been demonstrated here in several U.S. organic shale case studies, the fundamental challenges it addresses will make it a valuable solution for a range of unconventional reservoirs globally.
Summary It is common to produce some percentage of water during the oil‐extraction process. Conventionally, some water‐disposal wells are drilled in an oil field to inject these useless and hazardous waters. Mineral scale formation is a critical issue in water‐injection wells and may result in well plugging and an injection rate decrease in these wells. The two steps of mineral scale formation are scale precipitation and scale deposition. Two main mechanisms of inorganic scale precipitation are incompatibility between injected water and reservoir formation water and changes in the thermodynamic state of injected water. The injectivity of the well decreases because of deposition of supersaturated precipitated scales through the well column and near‐wellbore region. Currently, limited research has been done to evaluate inorganic scale deposition, and most of the research is limited to calculation of total scaling by commercial software. In this study, the mineral scale precipitation is evaluated by software modeling and laboratory experiments in an Iranian oil field, and the effect of the scale deposition phenomenon is assessed on permeability impairment and injection rate decrease. One of the major novelties of this work is simulation of various scale‐deposition models by coupling MATLAB® software coding and a reservoir simulator. The accuracy of different deposition models is analyzed by comparing them with field data (real water‐injection well) and laboratory tests (coreflooding test). Finally, our simulation results show that a single deposition model could not exactly predict the scaling phenomena in the studied carbonate reservoir that is supersaturated with CaCO3 and CaSO4. It is recommended to improve the scale‐formation prediction with a mixed deposition model supported by reliable static/dynamic modeling and experimental analysis.
Swiss oil trader Vitol said on 30 April that its oil and gas subsidiary, Vencer Energy, was buying Hunt Oil Company's assets in the Permian Basin for an undisclosed sum. Media outlets including Bloomberg and Reuters cited sources that pegged the asking price at around $1 billion. Houston-based Vencer was established last year as the trading giant's first foray into the upstream sector. The assets include leases on 44,000 acres in the Midland Basin side of the Permian, with an output about 40,000 BOE/D. "This is an important day for Vencer as it establishes itself as a significant shale producer in the US Lower 48. We expect US oil to be an important part of global energy balances for years to come, and we believe this is an opportune time for investment into an entry platform in the Americas," said Ben Marshall, the head of Vitol's Americas business unit.
ABSTRACT The industry is facing significant challenges due to the recent downturn in oil prices, particularly for the development of tight reservoirs. It is more critical than ever to 1) identify the sweet spots with less uncertainty and 2) optimize the completion-design parameters. The overall objective of this study is to quantify and compare the effects of reservoir quality and completion intensity on well productivity. We developed a supervised fuzzy clustering (SFC) algorithm to rank reservoir quality and completion intensity, and analyze their relative impacts on wells' productivity. We collected reservoir properties and completion-design parameters of 1,784 horizontal oil and gas wells completed in the Western Canadian Sedimentary Basin. Then, we used SFC to classify 1) reservoir quality represented by porosity, hydrocarbon saturation, net pay thickness and initial reservoir pressure; and 2) completion-design intensity represented by proppant concentration, number of stages and injected water volume per stage. Finally, we investigated the relative impacts of reservoir quality and completion intensity on wells' productivity in terms of first year cumulative barrel of oil equivalent (BOE). The results show that in low-quality reservoirs, wells' productivity follows reservoir quality. However, in high-quality reservoirs, the role of completion-design becomes significant, and the productivity can be deterred by inefficient completion design. The results suggest that in low-quality reservoirs, the productivity can be enhanced with less intense completion design, while in high-quality reservoirs, a more intense completion significantly enhances the productivity. Keywords Reservoir quality; completion intensity; supervised fuzzy clustering, approximate reasoning,tight reservoirs development