bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Engineering Gold Rush in Investment Banking
Authors: Brown Jeff 
Published: October 2015

HR Discussion
In the wake of the 2008 financial crisis, the investment banking industry was vilified by most of US (and perhaps rightfully so) as one of the main facilitators of “The Great Recession.” We cheered on as the industry was subject to an onslaught of new federal regulation, forcing many investment banks to slash thousands of jobs and drastically cut compensation for those on Wall Street. It is almost poetically ironic that with the recent downturn in the energy industry, investment banking (specifically energy investment banking) is well-positioned to not only weather the storm, but flourish in the current environment.
Those who have followed the market closely in recent months are likely aware that the drop in commodity prices has forced many operators and service providers to slow production, cut costs, and restructure their current portfolios. The general consensus of industry experts is that it is only a matter of time before the industry sees a sizeable wave of merger and acquisition deals and consolidation. Consequently, energy investment banking groups are not only capitalizing on said restructuring, but will be one of, if not the main, beneficiaries as many companies in the industry will be forced to sell off assets and/or consolidate.
Before diving into the specifics of what this means from a hiring perspective, it is important to understand how the energy investment banking industry, and particularly acquisitions and divestitures (A&D) groups, have evolved over the past 10 years.
Before 2005, any type of transaction facilitated by an investment bank that required nuanced, technical due diligence was almost always outsourced to a third party engineering agency. For example, if an operator intended to divest an asset, an investment bank would be engaged to represent and advise on the divestiture, with any technical analysis likely handled by an independent advisory. The investment bank would take the findings of the third party agency and incorporate its analysis in determining the price/ fair market value of said assets. Senior level investment bankers would then pitch the potential acquisition to prospective buyers.
As the energy investment banking industry became increasingly competitive, many investment banks began to realize a competitive advantage by conducting in-house technical analysis and evaluation for their clients. One example of this was Jefferies acquiring Randall & Dewey, a large and reputable independent oil and gas advisory firm, in February 2005. Through this acquisition, Jefferies was able to realize the value of conducting in-house technical analysis. Moreover, having seasoned reservoir engineers and geologists accompany traditional investment bankers as they pitched to C-suite executives (many of whom are engineers or geologists by background) proved to be paramount in winning new business.
Gelation of a Water-Shutoff Gel at High Pressure and High Temperature: Rheological Investigation
Authors: El-Karsani Khalid S.M. , Al-Muntasheri Ghaithan A. , Sultan Abdullah S. , Hussein Ibnelwaleed A. 
Published: October 2015

Summary
Polymeric gels are used to reduce or shut off excess water in petroleum reservoirs. The strength of polymeric gels needs to be high enough to withstand the water flow. This study investigates the strength of an organically crosslinked polyacrylamide (PAM) with polyethylenimine (PEI) as crosslinker. Dynamic testing measurements at high temperatures up to 130°C (266°F) and high pressure (500 psi) were used. During the gelation process, the rate of crosslinking increases with increased temperature. However, after the crosslinking reactions were completed, G′ was lower at higher temperatures than at lower temperatures. Polymer concentration has a stronger impact on G′ in comparison with the crosslinker. Salinity of mixing water has a negative impact on G′. High G′ was observed in distilled water (1044 Pa) in comparison with field water (725 Pa) at 130°C (266°F). Moreover, samples prepared at alkaline and acidic conditions produced stronger gels compared with samples prepared at neutral conditions. However, the gelation time is longer at a pH of 7. Ammonium chloride is found to be a very effective retarder in comparison with NaCl. The yield stress of the gel was correlated to the pressure gradient for the gel extrusion through fractures. It was found that gels with 7:0.3 and 5:0.3 wt% PAM/PEI gave pressure gradients of 155.5 kPa/m (55.2 psi/m) and 3572 kPa/m (518 psi/m), respectively. The decrease or increase in gel strength was explained through the impact of the different parameters on PAM hydrolysis.
Normalization of Analog Horizontal Wells for Type Curve Generation in Tight Gas Plays
Authors: Yu Shaoyong , Gouveia Jim 
Published: October 2015

Abstract
A mature reservoir is usually characterized with a number of both vertical and horizontal wells, which may both contribute to a significant recovery to-date. When considering forecasting for new wells in the geological similar areas (GSAs), it is common practice to generate a type curve by harnessing historical production data from analog wells. But, given varying well types and completion practices (e.g. different horizontal wellbore length), the analog assumption may be challenged.
When working on type curve generation, the common questions frequently asked are:Do we need to normalize analog wells for the type curve generation?How to conduct the normalization on both wellbore length and completion parameters?
It seems that the answer to the first question is a very obvious yes if the new wells will be designed differently from the analog wells – particularly if the lateral length and completion method is not similar. As a result, Estimated Ultimate Recoveries (EURs) and the Initial Production (IPs) will need to be normalized from those analog wells to a desired new wellbore length.
After having investigated both analytically and numerically the impacts on Recovery Factors (RFs) and the IPs from those factors of horizontal wells that include horizontal wellbore length (L), fracturing spacing/stages (nf) and drainage area (A), or well spacing, it is found that: RF will be directly affected by the wellbore length. There is linearity between RF and L when the latter is less than a certain value. The fracturing spacing/stages and drainage area (well spacing), however, will affect RF when the reservoir matrix permeability is extremely low.Also, IP has a high positive correlation with lateral length. In fact, these two variables have high linearity. In addition, fracture spacing will have a large impact on IP rates; however, drainage area will not at all. Note that these conclusions presume that wellbore hydraulic considerations are not a constraint. Further, lateral length presumes an effectively stimulated horizontal section.
The specific scope of this study is to provide a systematic normalization technique. Dry gas and wet gas case studies from the Western Canadian Sedimentary Basin (WCSB) have been adopted to demonstrate the workflow. Further, sequential accumulation statistical logic has been successfully applied to validate the premise of lateral length and fracture spacing as the key normalization variables.
It is believed that this methodology is rigorous for dry and wet gas reservoir systems. Moreover, this methodology is also applicable to richer gas-condensate and oil plays; however, broader relationships need to be established and tested before any conclusions can be drawn with wellbore hydraulic dynamics being taking into account as an effective factor.
MPD Allows Operator to Safely and Efficiently Drill Challenging Wells In Kobes (Montney Formation) in British Columbia
Authors: Weatherhead S. , Djidjelli A. , Leeds M. , Mujumdar H. 
Published: October 2015

Abstract
Interest in the unconventional shale gas plays continues to grow in Western Canada. The Montney formation found in North Eastern British Columbia can be particularly challenging due to drilling in the Canadian Foothills. Wells in the area are known for deep, hard, abrasive and abnormally pressured formations. Further challenges include unexpected fractures, lost circulation and coals seams. The combination of these drilling issues can cause a significant increase in expected drilling times (slow ROP and NPT).
Following some difficulty drilling offset wells due to well control issues, future designs incorporated a higher, more conservative mud weight. This let to slower ROP and corresponding NPT.
A new approach with MPD and lighter mud weight was proposed. For the intermediate sections, the first well changed from a weighted to un-weighted invert emulsion. The second well was drilled with a pure base oil system to lower the fluids solids content. The horizontal section was initially planned to drill with a density of 1400kg/m3 weighted invert. A MPD program was proposed drilling with a 1250kg/m3 weighted invert for the next two wells and adjusting backpressure to match the required bottom hole ECD.
The key operational objectives for the operator were increased ROP and a reduction of NPT. This was accomplished by lower ECD associated with lower mud densities, lower drilled solids and lower viscosities. A secondary benefit was the reduction of whole mud losses. Mud losses were reduced in manner that allowed for fast safe well control in the event a pressured fracture (kick) was encountered.
A reduction of more than 7.4 days vs AFE from spud to rig release was largely attributed to utilizing MPD technique and the team work of everyone involved on location. NPT was reduced from 100 hours to 8 hours on the final well of the project. The second MPD well of the project was considered a big success, with the following results (refer table 1).
Table 1 MPD2 vs Best Conventional well Performance Data Intermediate Hole Performance Main Hole Performance MPD#2 Well Best Conventional Well MPD#2 Well Best Conventional Well Bit Runs 3 4 3 8 Depth Length (m) 918 880 3080 2368 Time (hr) 41 77.5 243.75 290.3 ROP (m/hr) 26.5 11.55 11.3 8.025
As the activity in NE British Colombia's Montney play continues to grow, it is important that other operators learn the benefits of utilizing MPD. This includes safely decreasing days on the well by increasing ROP and reducing influx and losse related NPT caused by excessive mud weight.
The Effect of Kerogen-Hydrocarbons Interaction on the PVT Properties in Liquid Rich Shale Plays
Authors: Pathak M. , Deo M. D. , Panja P. , Levey R. A. 
Published: October 2015

Abstract
In liquid rich shale plays, the hydrocarbons may remain associated with the parent kerogen. During catagenesis of kerogen in the geologic history, the kerogen is converted to hydrocarbons. A fraction of the generated hydrocarbons is expelled from the residual kerogen matrix, while the rest is retained within the kerogen matrix. In liquid rich shale plays, the hydrocarbons retained within the kerogen plays a key role in estimated ultimate recovery (EUR). However, the vapor-liquid equilibrium between oil and gas in shales is affected by the presence of kerogen. The conventional compositional simulators ignore this kerogen-fluid interaction in calculation of pressure-volume-temperature (PVT) properties which leads to vastly different results.
The swelling of kerogen in the presence of solvents has been experimentally studied in previous works. These experiments suggest that the hydrocarbons expelled from the kerogen structure remain in a multicomponent equilibrium with the kerogen matrix. Molecular Dynamics Simulations (MDS) techniques have been used in the current paper to confirm the swelling behavior of kerogen in presence of solvents. The retained hydrocarbons stay in the dissolved form within the kerogen matrix. Considering the cross-linked nature of kerogen, there have been studies of the equilibrium behavior between the kerogen matrix and the expelled hydrocarbons using an extended Flory-Rehner Regular Solution theory model. The effect of this equilibrium between the expelled fluids and the kerogen matrix on PVT properties has been studied in the current paper. The vapor liquid equilibrium between oil and gas in the expelled hydrocarbons has been solved together with the kerogen-expelled hydrocarbons equilibrium.
The kerogen-fluid interaction in liquid rich shales affects important reservoir fluid properties such as saturation pressures, gas oil ratios (GOR) and formation volume factors leading to changes in produced GOR. A thermodynamic model has been proposed in the current study to calculate changes in above properties due to the kerogen-fluid interaction. The PVT properties calculated with the proposed model account for the kerogen-fluid interaction and will significantly change the predicted recoveries from liquid rich shale plays
Growth of Fractured Zone Around Hydraulic Fracture
Authors: Geilikman M. B. , Wong Sau-Wai , Karanikas J. M. 
Published: October 2015

Abstract
Propagation of fractures, hydraulic fractures included, is accompanied by growth of a certain process zone or "crack layer" around the fracture. This process or hydraulically fractured zone (HFZ) can be either smaller or larger depending on the properties of formation. The goal of this paper is to determine how the extent of HFZ depends both on rock properties and operational parameters as well. A better understanding of the HFZ is important because growth of hydraulically fractured zone can significantly increase permeability adjacent to the fracture leading to improved hydrocarbon production. More energy is required to induce an HFZ than just creating the main hydraulic fracture itself but a larger extent of HFZ leads to lower elastic energy for the same cumulative volume of pumped fluid. In order to adequately describe the entire hydraulic fracturing process, all main energy contributions should be taken into account. Traditionally, in using linear elastic fracture mechanics (LEFM) to model the hydraulic fracturing process we would predict creation of large planar fracture or even fractures without considering the possibility of developing an HFZ around the main hydraulic fracture. In this paper, a new description of hydraulic fracturing based on the Least Action Principle, is proposed to appropriately account for the potential development of an HFZ. Since hydraulic fracture for Unconventional Resource is induced by injection of large volume of fracturing fluid into tight rock formations, it is therefore convenient to formulate the model in the Rice-Cleary framework where "undrained" rock parameters are used. Elastic interaction of the hydraulically fractured zone with surrounding rock is described using Eshelby inclusion approach. It can be demonstrated that when the model is applied to the propagation of a single hydraulic fracture, the model reduces to the conventional (Geertsma-de Klerk) regime of fracture growth. As a result, the extent of the hydraulically fractured zone and its permeability can be expressed in terms of rock properties and key operational parameters (e.g. pumping rate, etc.). Validity of this model will require further work, especially in the laboratory experimental arena as well as analysis of field observations.
Modeling Two-Phase Flowback Data Using an Open Tank Model
Authors: Xu Y. , Fu Y. , Ezulike D. O. , Dehghanpour H. , Virues C. J. 
Published: October 2015

Abstract
In a previous paper (SPE 17163), a v-shape Gas-Water-Ratio (GWR) was observed and discussed from eight wells completed in the Horn River Basin, based on which the flowback data were divided into Early Gas Production (EGP) and Late Gas Production (LGP). The negative sloping GWR observed during EGP was assumed to be a ‘fracture cleanup’ period with negligible influx from the matrix system and a closed-tank model was developed for the fracture system to analyze flowback data. However, the effective fracture network is actually an open system which allows fluid influx from the surrounding matrix blocks. In this paper, we extend the previous model by considering the effect of gas influx during EGP.
Analyzing flowback data requires challenging mathematical procedures, which in most cases are still insufficient to capture the complexity of the two-phase flow in the fracture network. Material Balance Equation (MBE) is a simple but convincing tool in that it eliminates the assumptions lying in the flow equations. This paper seeks to use the MBE technique to analyze early-time two-phase flowback data in shale gas reservoirs. Diagnostic plots from field production data show an immediate gas breakthrough and a negative GWR trend at the beginning of flowback, which indicate the presence of initial gas in the fractures before opening the wells. Based on this observation, we develop a model to describe gas and water production during the early hours of flowback. The early-time two-phase production comes from an ‘effective fracture system’ initially saturated with gas and water. The model considers four drive mechanisms including gas expansion, water expansion, fracture closure and gas influx from matrix. Further, we propose a procedure to analyze field data using different forms of MBEs. It allows the estimation of the effective fracture volume which is difficult to measure in field cases. Finally, we demonstrate the application of the proposed material balance model by analyzing flowback data of one well completed in the Horn River Basin.
History-Matching and Forecasting Tight Gas Condensate and Oil Wells Using the Dynamic Drainage Area Concept
Authors: Clarkson C. R. , Qanbari F. 
Published: October 2015

Abstract
Recently, low-permeability (tight) gas condensate and oil reservoirs have been the focus of exploitation by operators in North America. Multi-fractured horizontal wells (MFHWs) producing from these reservoirs commonly exhibit long periods of transient flow during which two-phase flow of oil and gas initiates due to well flowing pressures dropping below saturation pressure. History-matching and forecasting of such wells can be rigorously performed using numerical simulation, but this approach requires significant data and time to setup. Analytical methods, while requiring less data and time to apply, have historically been developed only for single-phase flow scenarios. In this work, a novel and rigorous analytical method is developed for history-matching and forecasting MFHWs experiencing multi-phase flow during the transient and boundary-dominated flow periods.
The distance of investigation (DOI) concept has been used for many years in pressure transient analysis to estimate distances of reservoir boundaries to wells, amongst other applications. In the current work, the DOI concept is used to estimate dynamic drainage area (DDA) for the purpose of forecasting of tight gas condensate and oil wells – a linear flow geometry is assumed. During transient flow, the DDA is calculated at each timestep using the linear flow DOI formulation; a multi-phase version of the linear flow productivity index equation and material balance equations for gas and condensate/oil are solved iteratively for pressure, saturation, and fluid production rate. The productivity index equations for gas and oil utilize pseudopressure which is evaluated with saturation-pressure relationships derived from PVT data. For boundary-dominated flow, when the drainage area is static, the inflow equations are again coupled with material balance for both phases.
The new method is validated against numerical simulation, covering a wide range in fluid properties, and operating conditions. The new method matches simulation acceptably for all cases studied. Field examples of MFHWs are also analyzed to demonstrate the practical applicability of the approach. The three liquid-rich shale examples analyzed were also chosen to represent a wide-range in fluid properties. In all cases, acceptable history-matches are achieved.
The new analytical forecasting/history-matching procedure developed in this work provides a practical alternative to numerical simulation for tight gas condensate/oil experiencing two-phase flow during the transient flow period. The method, which does not rely on Laplace space solutions, is conceptually simple to understand, easy to implement, and avoids the inconvenience of Laplace space inversion.
Determining Well-to-Well Connectivity in Tight Reservoirs
Authors: Mirzayev Mammad , Riazi Naimeh , Cronkwright David , Jensen Jerry L. , Pedersen Per K. 
Published: October 2015

Abstract
Drilling and fracture stimulating horizontal wells in economically marginal fields, such as tight oil reservoirs, is a common practice. Estimating the connectivity between these wells (IWC) is important for the design and management of a field when waterflood recovery is applied. For example, IWC affects the determination of fracture conductivity and length and can help identify favorable locations for infill drilling and optimize injection rates.
Numerical simulators, such as streamline simulation need a geological model to determine IWC. Constructing the geological model, however, may take months. In this paper, we show how an alternative method, developed for and successfully applied in conventional reservoirs to determine IWC, can be modified to estimate tight formation IWC using solely production- and injection-rate fluctuations. The model is based on the Capacitance Model, or CM, and is modified to include a pseudo well (CM-PW).
The CM-PW is tested with various heterogeneous simulation cases and field data. The CM-PW can identify inter-well heterogeneities and differentiate them spatially. We observed that in some cases the CM-PW performs better than streamline simulation results while calculating production allocation factors. The CM-PW detects whether all the injected fluid volume goes to producers. The model accuracy is based on the match to production data and, for all simulation cases, the model accuracy R2 ≥ 0.83. The field application, from a tight oil waterflood in the Bakken Formation, shows that the CM-PW results agree with tracer test results and field reports showing fracture hits between wells. Seismic interpretations also strongly support the CM-PW evaluations.
The IWCs evaluated by the CM-PW during unsteady state flow periods provide key information to make a favorable decision at the early stage of water flooding in tight oil formations. Integrating the connectivity analysis, with tracer tests, seismic, and the geology enabled us to determine the reasons for the connectivity observed, identifying whether injected fluid flows through geological bodies or fractures between an injector-producer pair.