bluuebunny/crossref_metadata_2025_split huggingface dataset:
Work Flow Integration, Best Practices, and Technological Solutions for Improving Productivity in Mature Fields
Authors: M. de Jesus Gonzalez , M. Suarez Corvo , M. Mora Villa 
Published: June 2014

Abstract
More than 70% of global oil production derives from mature fields. With current elevated prices, the revitalization and optimization of these fields are of great commercial appeal and interest. However, revitalization requires technologies and procedures for quick analysis and diagnosis of the field in addition to established technical solutions to help improve productivity and counter high levels of pressure and production decline.
In 2013, in the southern region of Mexico, workflow integration for integral analysis of well productivity in mature fields and naturally fractured carbonate reservoirs, in combination with joint efforts of several product service lines and their technological solutions, have been key to identifying a portfolio of opportunities for well interventions. Of which, in a short time period, an increase to production of 1, 843 STB/D of oil was achieved, with only 54.5% of the proposed activity involving well services.
In view of the energy requirements in the world and the low rate of discovery of new reserves, many companies have targeted maximizing the exploitation of mature fields. Therefore, this study intends to establish effective techniques, methodologies, best practices, and lessons learned developed by multidisciplinary teams performed in Mexico during the past eight years. This strategy has helped increase oil and gas production in areas where it was previously considered unlikely because of complexity issues, such as low pressures, low permeability, organic deposits, scales, advanced fluid, reservoir dynamics, and mechanical problems, among others. These efforts have resulted in highly successful solutions as well as added value to the national operator.
Brackish Water as a New Water Resource for Energy Development
Authors: Stewart David R. 
Published: June 2014

Abstract
This paper will discuss the need for additional water resources associated with energy development and the potential of utilizing brackish groundwater as a new water resource. Brackish groundwater used in this context is a water that would have a total dissolved solids content of 4,000 mg/l or higher to a maximum of 50,000 mg/l. These types of groundwater are found throughout the world in areas where oil and gas wells are being developed. Key factors are indicating a conflict between energy development and water uses along with agricultural needs. These conflicts arise from the increase in population and the need for additional water sources, traditional water sources are dwindling in both quantity and quality, energy intensive treatment technologies such as RO or UV treatment and the need for additional water sources due to the requirements of the growing poplution for food resources. For these reasons, it will be important to develop and enhance all of our water resources for future uses. Brackish groundwater can play a significant role in this area.
Using Production Gas Carbon and Hydrogen Stable Isotope Signatures to Predict Fluid Quality: Wattenberg Field, Colorado, USA
Authors: Travers Patrick , Cumella Steve , Dolan Michael 
Published: June 2014

Abstract
Stable carbon (δ¹³C) and hydrogen (δ²H) isotopes have been used to characterize hydrocarbons for exploration, development and production since the 1960s, and have re-emerged as predictive tools with the development of unconventional "tight" oil and gas plays. Here we report on publicly available Colorado Oil and Gas Conservation Commission (COGCC) and U.S. Geological Survey (USGS) datasets of production gases collected from the Greater Wattenberg Area (GWA) of Colorado.
The δ¹³C and δ²H of natural gas can be used to interpret gas origin (i.e., bacterial versus thermal), hydrocarbon maturity, migration and reservoir compartmentalization, and production allocation. Maturities derived from carbon and hydrogen isotopes can serve as controls in regional maturity maps, which are used to help define areas of oil, wet gas and dry gas production. Stable isotope analysis can be executed pre-completion on samples obtained from mud gas and/or gas desorbing from cuttings and core. These data can help predict fluid type, API gravity, and gas-oil ratio (GOR), all of which can help guide land acquisition and development decisions.
Production gases from the lower to upper Cretaceous Muddy "J" Sand, Codell, Niobrara and Sussex formations are characterized isotopically as early-mature to post-mature oil-associated gases. Progressing from shallow to deeper formations, δ¹³C of methane, ethane, propane and δ²H of methane components all increase, reflecting increasing maturity with depth, and the presence of multiple, discrete petroleum systems (Sherwood et al., 2013). Stable carbon and hydrogen isotope values show a strong correlation to both initial and cumulative GOR for the unconventional Niobrara and Codell intervals of Wattenberg Field. While this relationship does not hold for wells actively producing from the Muddy "J", this could be a result of geologic compartmentalization in this interval due to faulting, natural migration and other factors.
Validation of the correlation between Niobrara and Codell production GOR and stable isotope composition was provided by an independent geochemistry dataset from the USGS. The predicted GOR values were then used to accurately distinguish reservoir fluid classification. These results demonstrate the potential of natural gas stable isotope signatures as a useful and reliable fluid quality prediction tool.
Verification of a Proppant-Filled Discrete Fracture Network Model
Authors: McKenna Jonathan P. 
Published: June 2014

Abstract
Effective propped fracture half-lengths following a typical hydraulic fracture stimulation of a wellbore can be difficult to quantify. Therefore, different techniques for modeling proppant distributions must be applied to the same dataset for validation purposes and to gain insight into the actual proppant distributions. A proppant-filled fracture model is applied to one well targeting the Evie Member of the Horn River Formation (British Columbia, Canada). Another technique for identifying microseismic signatures associated with the initial slickwater pad and the proppant-laden fluid was applied to the same well to obtain observed proppant distributions. The similarity of the proppant distributions from the two techniques gives validation to each procedure and the results can be used to optimize future completion techniques.
Unconventional Horizontal Well Placement Challenges - LWD Geosteering Applications Utilizing a Unique Spectral Azimuthal Gamma Ray in Real Time
Authors: Diab Mohamed , Combs Jeremy 
Published: June 2014

Abstract
Placing horizontal laterals in the sweet spot of unconventional reservoirs is challenging. As more unconventional wells are drilled, there is growing evidence that the old way of geosteering homogeneous conventional reservoirs is not sufficient. Challenges due to smaller pore sizes, tinier pore throats, and less permeable rock are limiting production from unconventional reservoirs. Well bore placement for optimal fracture propagation is also an issue and laminations within a single geological layer can prevent oil companies from placing their wells in the sweet spot of the reservoir.
A unique logging-while-drilling (LWD) spectral azimuthal gamma ray (SAGR) tool has been developed that provides high-quality images and spectral elemental analysis, which allows geosteering in the lateral section of unconventional shale reservoirs; the use of the uranium content curve while drilling helps with placing the well in the sweet spot of the reservoir.
Several applications are discussed in this paper, including pre-planning and modeling, kicking-off through the landing, and geosteering in the zone for the maximum production. The significance of these applications is to demonstrate how innovative geosteering techniques can prove useful in more challenging unconventional reservoirs.
Optimizing Efficiency in Horizontal, Multi-Stage Fracturing Operations through E-line Conveyance—Case Study from the Bakken
Authors: Mann Rex , Bukowski Rick 
Published: June 2014

Abstract
In the Bakken, pump-down perforating has been the preferred solution for multi-stage ‘plug & perf’ operations for years. However, when an operator in a Bakken, North Dakota field was faced with a restricted inner diameter, they turned to an unconventional solution of using e-line, tractor-based conveyance. The operation was a success and more such operations have been run. This paper will present the lessons learned from these operations, as well as discuss the applicability and efficiency gains of e-line, tractor-based conveyance. Best practice consideration will be proposed for future plug & perf operations in horizontal wells.
Several challenges led to the initial decision to select the tractor-conveyed solution. Poor road conditions made the logistics of heavy equipment difficult, and coupled with severe time constraints and strict budget considerations the e-line solution became the preferred choice. This decision enabled the operator to get this $9M asset on production in a timely manner.
A 3.6 in. patch was restricting the inner diameter of a 4½ in., 11.6# casing string. The operator needed to plug and perforate 26 zones horizontally from 21,740 ft up to 11,830 ft to get the well on-line quickly. Pumping the 4½ in. plug was not considered an option due to the risk of premature setting or pumping off plug and/or guns resulting in expensive and time consuming fishing operations. Coiled tubing would only be able to reach the first 16 zones leaving 10 zones imperforated. Rig operations would be too time consuming and costly.
The 26 run, e-line operation was completed in 14 days with no conveyance mis-runs or lost time but only one gun mis-fire. The well was brought on-line quickly and the logistical challenges easily overcome due to the lightweight nature of the e-line technology. As an added bonus the operation offered several HSE benefits stemming from the low footprint, reduced personnel requirements, and less heavy lifting.
An Analytical Method for Optimizing the Spacing of Transverse Fractures in Liquid–Rich Shale Formations
Authors: Li J. , Guo B. 
Published: June 2014

Abstract
Producing oil from liquid-rich shale fields requires well completions with multi-stage hydraulic fracturing to enhance well productivity. Good design of transverse fractures is a key to achieving successful well completion and field-development economics. Using large fracture spacing will limit the number of fractures along the horizontal wellbore of given length, while using small fracture spacing can result in merging of fractures in the fracture-shadow area, both will reduce well productivity and oil recovery factor. There exists an optimum fracture spacing for given geological and fracturing conditions that allows the maximum oil recovery factory in shale oil reservoir to be achieved. The current practice of determining the optimal fracture spacing involves running numerical simulators to identify the fracture shadow. The numerical method is not only time-consuming but also inaccurate due to the procedure of numerical analyses and visual identification of fracture shadow. This paper presents a simple analytical method to determine the minimum fracture spacing required for preventing fracture-merging.
On the basis of assumption of constant-width fracture, an analytical solution was first obtained in this work to predict the stress distribution around an existing fracture. The solution was then used to predict the boundary of fracture-shadow area and identify the minimum distance of new fracture from the existing fracture to avoid fracture-merging. The result of the analytical method was compared with that of a numerical model of Finite Element Method (FEM) for a typical fracturing condition in a shale formation. The comparison indicates that the new analytical solution gives a shorter fracture spacing that will increase oil recovery factor. According to the analytical solution, the minimum required fracture spacing is nearly proportional to fracture width and insensitive to the fracture length. The minimum fracture spacing does not exist when the net closure pressure is lower than a critical value, depending on the in-situ stress contrast and Poisson's ratio of shale. This paper provides engineers a simple tool for optimizing their well completion in liquid-rich shale formations.
Case Study: Steam Injection Step Rate Tests Run in the Shallow Low Permeability Diatomite Formation, Orcutt Oil Field, Careaga Lease, Santa Barbara County, California
Authors: Elias Ramon , Marquardt Ian , Medizade Mason 
Published: June 2014

Abstract
Cyclic steam stimulation (CSS) has been used in California since the 1960s. It has been used as an effective method for commercial oil recovery from the very low permeability diatomite formation since about the mid-1990's. Santa Maria Energy (SME) operates a CSS project in the Opal A diatomite of the Sisquoc formation on the Careaga Lease in the Orcutt Oil Field in Santa Barbara County, California. A 19-well CSS pilot has been operational since October, 2009. SME has received entitlement to proceed with an expansion consisting of 110 additional new wells.
The CSS process designed by SME for the diatomite zone is one that works without fracturing the reservoir rock. An earlier paper was presented that describes techniques used for monitoring steam injection to help keep the injected steam confined to the zone of interest1. One such technique is Hall's method2 for water injection and adopted for steam. Corresponding algorithms have been programmed into a supervisory control and data acquisition (SCADA) system to survey and analyze all steam injection cycles for all wells. The method has also been used to analyze steam injection step rate tests (SRT). This paper discusses:
Two SRT's performed using steam injection; The analytical techniques used; and The results.
Of special importance is that matrix flow is seen for CSS even though the injection bottom-hole pressure exceeds that which might normally be considered the rock fracture or parting pressure. This is due to partial plugging and other phenomena during steam injection that occurs to an extent not realized in more permeable rocks (such as very high permeability sandstones). These effects produce extra pressure drop during steam injection into the diatomite zone. This raises questions about the misuse of tubing wellhead pressure readings during steam injection as a reliable indicator of the reservoir formation parting pressure. As a result of this and other work, SME has adopted a specific range of CSS injection rates that are below a critical rate to help insure steam injection is confined to the zone of interest.
Effect of Well Down Spacing on EUR for Shale Oil Formations
Authors: Bharali Susrut Gautam , Sharma Akash , Sehra Sarva Shakti 
Published: June 2014

Abstract
With the shift in focus towards unconventional oil and gas as the future of the oil and gas industry, it has become essential to optimize performance of wells in these formations and ensure economic feasibility in these unpredictable scenarios. Down Spacing of wells is a procedure by which we reduce the space between the laterals of two wells to maximize recovery from the formation. In conventional reservoirs, due to the homogeneity in petro-physical parameters of the formation, down spacing is usually not economic as the lower number of wells would also be sufficient to achieve optimum productivity, furthermore, the wells will have a tendency to cannibalize each other's production. However, in unconventional reservoirs like shale, down spacing becomes essential to maximize reserves and the productivity from them as poor permeability hinders majority of the pores to be reached by a relatively lower number of wells.
The presented paper, achieves to find the optimum down spacing distance that can be achieved between two fractured lateral wells in Eagle Ford Shale Play. The paper analyses the performance of group of wells with different well spacing in the Eagle Ford formation. The data used is from the public forum. The EUR/well is calculated using decline curve analysis. Fekete-Harmony has been used for calculation of EUR and then a simplistic cash flow analysis had been conducted to analyse the feasibility for each presented scenario. This paper also has a group of analog wells created in Fekete Harmony with drilling and completion techniques similar to the ones widely used in Eagle Ford Formation. Real world Eagle Ford geological and petrophysical parameters are incorporated into the Harmony model for the analysis of these wells.
This paper emphasizes on the need for downspacing in the shale oil reservoirs for optimum production. It also discusses the advantages and disadvantages of downspacing as well as looks into the economic side of this process.
Optimization of Hydraulic Fracturing Design under Spatially Variable Shale Fracability
Authors: Jahandideh Atefeh , Jafarpour Behnam 
Published: June 2014

Abstract
Current hydraulic fracturing designs are based on equal fracturing intervals, ranging from 50 to 600 feet, along the horizontal well with an equal half-length, ranging from 100 to 600 feet. However, symmetric spacing designs are only suitable for homogeneous shale fracability or brittleness, which may not be the case in many shale plays. The efficiency of the fracturing process depends on the fracability of the underlying shale rock. Therefore, the heterogeneity in shale fracability can have an important role in designing and optimizing the hydraulic fracturing process, in particular in identifying the optimal number, location, and length of the fractures. In this paper, we develop an optimization approach for hydraulic fracturing design under geospatial variability in shale fracability and investigate several aspect of the design and optimization of the fracturing process. The optimization of the hydraulic fracturing design is performed using the Simultaneous Perturbation Stochastic Approximation algorithm to maximize the net present value of the shale asset that includes the cost of fracturing and revenue from gas production. The proposed optimization framework provides a systematic hydraulic fracturing design and treatment approach for unconventional reservoirs to improve production and reduce the cost and environmental impacts of hydraulic fracturing. We demonstrate the effectiveness and suitability of the proposed method with several numerical experiments in shale gas development.
A Sensitivity Analysis of Input Parameters for Modeling Primary and Tertiary Recovery in Unconventional Oil Reservoirs
Authors: Givens Bill , Hoffman B. Todd 
Published: June 2014

Abstract
Reservoir flow simulation models for unconventional oils reservoirs like the Bakken are difficult to construct and condition to data. It is important, however, to have accurate models to evaluate primary recovery aspects such as well spacing and improved recovery options, such as gas injection. While performance of the model depends on all of the unknown reservoir parameters, it is important to understand which ones have the most significant effect on the accuracy of the model. This information can then be used to focus capital on gathering the most impactful data.
The data used for this analysis comes from the Elm Coulee Field in Eastern Montana. In this paper, we assess a number of different combinations of parameters to match the historical production data. The analysis focused primarily on four common model inputs for history matching: reservoir permeability/porosity distribution, dual-porosity dual-permeability modeling, heterogeneous z-direction permeability and hydraulic fracture modeling. The hydraulic fractures are represented on the grid, so the dual porosity properties account for the matrix and natural fractures. Using an expected range for each input, the change in reservoir performance is determined not only for primary production but also for gas injection recovery operations.
Only the first 3 - 4 years of production is matched; then, the models are validated on the next 5 years of production data. The models predicted accurately with only 10% average error. Under primary recovery, porosity and effective permeability had the most impact on the simulated production rate, followed by hydraulic fracture dimensions. Under gas injection simulation, the porosity and permeability and the most effect on the output, with the other tested reservoir characteristics not making a significant contribution.
Having insight into what are the most significant parameters of a reservoir model can help limit money spent and time wasted on collecting less important data. This paper sheds light onto what those parameters might be in the Elm Coulee field. In addition, a methodology is developed to identify what these parameters might be for any type of reservoir engineering study.
A New Petrophysical Model to Define Porosity Components of Unconventional Reservoirs, Using Standard Open-hole Triple Combo Logs
Authors: Holmes Michael , Holmes Dominic , Holmes Antony 
Published: June 2014

Abstract
Unconventional reservoirs are composed of several types of porosity/hydrocarbon components - standard effective porosity, clay porosity, total organic carbon (TOC), and micro porosity associated with shales. Adsorbed hydrocarbons reside in the TOC component and "free" hydrocarbons in the effective porosity and shale micro porosity. An accurate definition of all these components is essential in defining the reservoir hydrocarbon resource volume.
TOC has a density response close to porosity and indeterminate neutron response. The log responses are probably related to the degree of thermal maturity.
Previous publications (Holmes, et al. 2011 and 2012) were earlier attempts to define these porosity components. This publication is a significant refinement, whereby TOC and clay log responses are determined using an iterative technique. An initial estimate of TOC properties (density vs. neutron) is subtracted from raw logs to derive a "TOC-free" log response. Then clay log responses are defined by subtracting matrix, effective porosity, and silt contributions. The resulting density/neutron cross plot is then compared with known clay mineral responses to determine if estimates of the various component log responses are reasonable. If not, these responses are adjusted and the procedure is repeated. A final check of the methodology is to calculate a reconstructed porosity, which is effective porosity + clay porosity + shale micro porosity, and see if it agrees with total porosity determined from the "TOC-free" reservoir model.
Examples of unconventional reservoirs - both gas and oil bearing - are presented.