bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Ways in Research and Education: The Effect of Real Field Data on Multi-Disciplinary Student Projects in Petroleum Engineering
Authors: Reinicke Kurt M. , Ganzer Leonhard , Teodoriu Catalin 
Published: October 2011

Abstract
When abandoning its "diploma curriculum" and implementing its bachelor/master program Petroleum Engineering in 2004, the Institute of Petroleum Engineering (ITE) of Clausthal University of Technology in Germany included a mandatory group project in the new curriculum. Group projects are interdisciplinary full time team efforts by approx. 6-8 students over approx. 8 weeks. Since 2008 all projects are carried out on real data from real fields. The recent group projects are defined around the data for five oil fields abandoned in the 1990ies at 15 USD/bbl scenarios. The data include seismic, logs, core and fluid data, production and injection data, abandonment information, well and field files. The data together with financial assistance were provided by a major oil company in Germany to allow students to work with the data and come up with plans for the redevelopment of the fields. University staff is coaching the groups with further support coming from industry experts. Results achieved by the students are presented at the end of the group projects in front of a panel formed by faculty and industry experts. In the process, the data providing Oil Company will receive a "peer reviewed" concept that may be further adapted to the company utilization.
Many SPE papers presented over the years the achievements of various universities through the aid of real field data and the student work. Yet we want to present a "real field data" project that has been successfully implemented at Institute of Petroleum Engineering (ITE), TU Clausthal, Germany. This paper summarizes the experience gained during more than 2 years of integrated group projects with real data and strong industry involvement.
Well Site Risk Screening: The Critical Few
Authors: Powell Bill D. , Van Scyoc Karl C. 
Published: October 2011

Abstract
Assessment of well risk potential is an important factor for well integrity management, yet there are few alternatives for rapidly screening production well site risk. Often, a small proportion of the total well inventory has the greatest risk; these wells warrant the most detailed analysis and allocation of resources to assure that well integrity is maintained. Wells with less operational risk may have proportionally fewer risk controls. Thus, for safety, environmental, economic and business reasons, on-shore oil and gas operators benefit by efficiently identifying the critical wells among the thousands being operated so that limited resources can be applied to gain the most benefit.
This paper reviews the development process for one such well site risk screening approach that combines safety and environmental risk criteria while assuring ease of use and application of sound risk principles. The paper outlines the development process along with the rationale for selection of primary screening criteria, key assumptions, approximations, and input data. Furthermore, the authors reflect on the key learnings following application of the screening method for over 10,000 operating wells in North America.
Keywords: Well Integrity, Risk Assessment, Consequence Modeling, Dispersion
Failure to Produce: An Investigation of Deficiencies in Production Attainment
Authors: Nandurdikar N. , Wallace L. 
Published: October 2011

Abstract
The economic importance of delivering on planned production volumes is undeniable. Over the last 15 years, however, the oil and gas industry's production attainment performance has degraded. Today, the average oil and gas project delivers only 75 barrels for every 100 barrels promised at sanction. This paper reports on a root-cause analysis conducted on over 145 oil and gas projects for which the authors have access to planned production volumes (at sanction), and 12 months to 60 months of actual production data. The authors use a detailed global database of oil and gas projects to conduct a rigorous statistical analysis of production attainment. The analytical strategy is to statistically connect "inputs" (i.e., information and practices used prior to sanction) to "outputs." The results show that poor production attainment is due to unreliable forecasts based on optimistic subsurface assumptions, failure of assurance processes, and lack of accountability for production volumes. Our analysis shows that project teams are overly optimistic about basic subsurface characteristics, especially in the absence of actual data. Assurance and decision analysis processes, such as peer reviews and risks modeling, are not successful in identifying optimistic forecasts. Every project with a significant production shortfall used these tools, yet these tools failed to flag the risks. Most companies lack a single point of accountability for delivering production. In most cases, no one is accountable if the production falls short of promise. These problems persist because companies do a poor job of conducting root-cause analysis to understand production shortfalls; only 30 percent of projects in this database conducted such an analysis. The analysis provides strong evidence that the industry has a problem in predicting production volumes. But the authors go beyond this observation and provide the reader with valuable take-aways, including specific causes of the problem and recommendations to eliminate, or reduce, this problem.
DFA Asphaltene Gradients for Assessing Connectivity in Reservoirs under Active Gas Charging
Authors: Zuo Julian Y. , Elshahawi Hani , Dong Chengli , Latifzai Ahmad S. , Zhang Dan , Mullins Oliver C. 
Published: October 2011

Abstract
Identification of reservoir compartmentalization, quantification of flow connectivity, and assessment of compositional gradients are critical for optimal reservoir characterization, production, and management, especially in deepwater developments. Downhole fluid analysis (DFA) provides a useful tool to measure composition, gas/oil ratio (GOR), density, and color (linearly associated with asphaltene content). In particular, DFA is the method of choice to measure gradients of reservoir fluids vertically and laterally. Based on DFA measurements and advanced asphaltene science, a new modified Flory-Huggins regular solution model that has been referred to as the Flory-Huggins-Zuo EOS has successfully been developed and used to delineate reservoir connectivity recently. It provides the industry's first predictive asphaltene grading equation of state (EOS) and has proven reliable to predict connectivity in equilibrated oil columns. The theory shows that asphaltene gradients can be large owing to both the gravity term and GOR gradients.
In this case study, we demonstrate that the methodology for equilibrated reservoirs can be extended to nonequilibrium oil columns. We employ the new asphaltene Flory-Huggins-Zuo (FHZ) EOS for a reservoir currently undergoing active charging of biogenic gas. Isotope analysis shows that the biogenic methane is not equilibrated in this column. Nevertheless, the local asphaltene concentration within the column is shown to be equilibrated with the local GOR value and gradient. Based on the properties computed by the Peng-Robinson EOS with methane influx, the FHZ EOS for asphaltenes - originally formulated for equilibrium columns - may also be used to model the asphaltene (color) gradient in this nonequilibrium oil column. The obtained 2-nm asphaltene diameter is also consistent with field and laboratory data and is part of the Yen-Mullins model of asphaltene science (size of asphaltene nanoaggregates). This methodology establishes a powerful new approach for conducting DFA color grading analysis by coupling the Yen-Mullins model, and the FHZ EOS with DFA to address reservoir connectivity in reservoirs under active gas charging.
Monitoring on CO2 EOR and Storage in a CCS Demonstration Project of Jilin Oilfield China
Authors: Ren Shaoran , Niu Baolun , Ren Bo , Li Yongzhao , Kang Wanli , Chen Guoli , Zhang Hui , Zhang Hua 
Published: October 2011

Abstract
Jilin oilfield, located in Jilin Province of Northeast China, is conducting the first large scale demonstration project on CO2 EOR and storage. During the first stage, CO2 separated from a nearby natural gas reservoir (20–97% CO2 content) is injected into the northern part of Hei-59 oil block. Currently, the targeted oil reservoir, with an area of 1.7 km2 and oil reserve of 0.78×106 tons, has six CO2 injectors and twenty-five production wells with an inverted seven-spot injector-producer pattern. Up to now, nearly 150,000 tons of CO2 has been injected for a miscible flooding, and an expected incremental oil recovery of 10% would be achieved. In order to better evaluate the reservoir performance and ensure a safe injection and long-term storage of CO2, a monitoring program has been designed and deployed to monitor the EOR performance and the state of CO2 in the reservoir.
The monitoring techniques used include CO2 tracers to monitor gas breakthrough in production wells and flow of CO2 across the reservoir, and bottom-hole pressure survey of producers to evaluate the miscibility effect on EOR combined with production data analysis. Geophysical techniques are also employed to detect possible fractures and their orientation and dimensions, which include electric spontaneous potential measurement and micro-seismic detections. Cross-well seismic is intended to monitor the flow and track the front of CO2 between wells. Data of geochemical monitoring from produced water can be used to estimate the amount of CO2 dissolved in reservoir fluids. CO2 dissolution in formation water and residual oil is one of the main storage mechanisms, which can greatly enhance the safety and effectiveness of subsurface storage. In this paper, the results of reservoir monitoring applied in the oilfield are present and analyzed, and forward work will be focused on optimizing EOR performance and verification of the geo-capacity storage in the targeted reservoir.
Game Changing Technology for Treating and Recycling Frac Water
Authors: Ely John W. , Horn Aaron , Cathey Robbie , Fraim Michael , Jakhete Sanjeev 
Published: October 2011

Abstract
This paper addresses an advanced oxidation and precipitation water treatment process employed as an on-the-fly fluid pretreatment during hydraulic fracturing operations. The water treatment technology will allow for substantial reuse of flowback and produced fluid while at the same time completely replacing liquid biocide and scale inhibitor fluid treatment during fracs. Additionally, the treatment process generates zero waste. To date, the technology has been used on hundreds of wells successfully treating over 17 million barrels. The paper will report on more than 2 years of field operations on hundreds of frac stimulations as well as numerous pilot operations in multiple shale plays. Dynamic tube-blocking tests show that the treated fluid will not deposit scale even after days of storage in an open frac tank. Field sample testing shows the injected brine has 3 to 6 log-cycle kill of sulfate-reducing and acid-producing bacteria populations. With the move toward environmentally safe chemicals, an economical process eliminating chemicals is a step forward for our industry. The equipment is purposely designed to segue directly into the fracturing process without interfering with service company pumping operations or having any compatibility problems with any service company products. Our paper will show definitive results from field operations of an economic water treatment system that will allow for a reduction in liquid chemical usage and closed-loop management of wastewater. The newest design would treat 80 barrels per minute, occupying a footprint roughly the size of a frac tank. The units can be deployed in tandem for higher flow rate requirements.
Integrating Fracture Diagnostics and Engineering Data in the Marcellus Shale
Authors: Mayerhofer Michael J. , Stegent Neil A. , Barth James O. , Ryan Kevin M. 
Published: October 2011

Abstract
This paper presents results from a group of Marcellus shale horizontal wells. The wells were completed in sequential order with preplanned fracture and reservoir diagnostics to better understand completion and stimulation efficiency and drainage patterns given a certain well spacing in the Marcellus Shale. Insights were gained by integrating microseismic fracture mapping, diagnostic fracture injection tests (DFITs), downhole pressure gauges, post-frac pressure transient analysis, nontoxic chemical tracer and production data.
Microseismic fracture mapping was performed during the completion of two offset horizontal wells. Since the two wells were completed sequentially, it was possible to deploy downhole pressure gauges in one well while the offset well was being completed. This procedure allowed for the unique opportunity to monitor potential communication between the two wells and correlate this with the overlap of microseismic activity. The gauge was also used to monitor the initial post-frac buildup in that well. A second buildup test was conducted after approximately 5 months of production.
The integration of various engineering data leads to interesting conclusions with respect to effective fracture length, correlation of microseismic events with actual hydraulic fracture communication, and production interference. These insights provide important information for optimizing infill drilling, well placement, and fracture completion strategies in the Marcellus shale.
A Variable Rate Solution to the Nonlinear Diffusivity Gas Equation
Authors: Barreto Abelardo B. , Peres Alvaro M. , Pires Adolfo P. 
Published: October 2011

Abstract
The hydraulic diffusivity equation that governs the flow of compressible fluids in porous media is nonlinear. Although gas well test analysis by means of the pseudo pressure function has become a standard field practice, the effect of viscosity and gas compressibility variation with pressure is often neglected. Moreover, in field operation, the gas well is submitted to a variable rate production in order to determine well/reservoir properties and an estimation of the absolute open flow (AOF). For slightly compressible fluids, variable rate can be properly handled by superposition in time. Unfortunately superposition cannot be offhand justified to gas reservoir due to its non-linear behavior. In this work a general solution which properly accounts for both fluid property behavior and variable rate is presented. The proposed solution, which is based on Green's Functions method by considering the viscosity-compressibility product change as a non-linear source term, can handle variable gas rate for several well and reservoir geometries of practical interest. From the general solution, an analytical expression for variable rate tests of a fully penetrating vertical well in an infinite gas reservoir is derived. This expression is applied to a synthetic data set to calculate the pressure response for a buildup test in an infinite homogeneous reservoir. The results compared to a finite difference numerical simulator shows close agreement. It is also shown that the dimensionless pseudo pressure converges to the slightly compressible fluid solution for long shut-in times. Thus, at such long times, Horner analysis and log-log derivative plot can be applied to obtain good estimative of reservoir parameters as already discussed previously in literature.
Surfactant Formulation Study for Bakken Shale Imbibition
Authors: Wang Dongmei , Butler Raymond , Liu Hong , Ahmed Salowah 
Published: October 2011

Abstract
This paper investigates an idea for chemical imbibition using surfactant formulations to stimulate oil recovery from oil shale. One goal of this research is to identify a formulation that promotes imbibition while minimizing clay swelling and formation damage. Experiments directed toward this goal involved balancing the temperature, pH, salinity, and divalent cation content of aqueous fluids to enhance oil recovery from the shale with ultra-low porosity and permeability in the middle member of the Bakken formation in the Williston Basin of North Dakota. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale, and examine the viability of a field application.
Using spontaneous imbibtion, brines and surfactant solutions with different water compositions were examined. With oil from the Bakken formation, significant differences in recoveries were observed, depending on compositions and conditions. Cases were observed where brine and surfactant (0.05–0.2 wt % concentration) imbibition yielded recovery values of 1.55 to 76% OOIP at high salinity (150–300 g/L: 15–30 wt %) and temperatures ranging from 23°C–120°C. Six key observations were noted: (1) an ethoxylate nononic surfactant, an internal olefin sulfonate anonic surfactant, and an amine oxide cationic surfactant were more stable than the other surfactants for temperatures from 105–120°C. They were effective in imbibing and displacing oil at high temperature. (2) Adding alkali to surfactant formulations increased oil recovery from Bakken shale. However, sodium carbonate reacted with divalent cations and precipitated when added to our highly saline brines. To counter this effect, sodium metaborate was added to surfactant solutions to reduce or prevent precipitation. (3) An ethoxylate nononic surfactant and an internal olefin sulfonate anionic surfactant were more tolerant of high salinity than other surfactants and display higher oil recoveries at high temperature. For Bakken cores, surfactants did not imbibe effectively using distilled or low salinity water. (4) Varying the hardness of the surfactant formulation had a major effect on imbibition and oil displacement. (5) In some cases, clay flaking from the shale was observed when contacting brine (without surfactant) or contacting amine oxide cationic surfactant with higher alkane numbers in brine. However, for the later situation, it could be improved by changing pH of surfactant solution. (6) For a given surfactant, oil recovery can be maximized by identifying the optimal surfactant concentration, brine salinity, sodium metaborate concentration, and divalent cation content.
Theory of Unipole Acoustic Logging Tools and their Relevance to Dipole and Quadrupole Tools for Slow Formations
Authors: Wang Tsili , Dawber Mike , Boonen Paul 
Published: October 2011

Abstract
A simplistic mathematical model has been developed to study a unipole acoustic logging tool. The model allows us to quantitatively relate a unipole tool response to monopole, dipole, and quadrupole tool responses, and vice versa. The interconnections between the different forms of excitation and reception provide some useful insights into the acoustic tool physics. The model is confirmed by numerical simulations.
The unipole flexural wave sensitivity to shear slowness has been carefully studied. Numerical modeling and slowness-time-coherence analysis show that unipole, dipole, and quadrupole appear to have similar sensitivity to the shear slowness of a slow formation. The dispersion results suggest that a unipole flexural wave cannot be dispersion corrected based on any standard wave mode such as a dipole mode. Instead, the dispersion effect needs to be corrected by considering the mode-mixing nature. The look-up table approach used for this study represents the first step in the development.
The unipole sensitivity to azimuthal shear anisotropy is studied. Substantial sensitivity is observed from the modeled responses in an azimuthally anisotropic medium. The same is true for a simplistic dipole tool. A conceptual quadrupole tool in the same formation shows reduced variation in waveforms with the rotation angle. Dispersion correction of the unipole flexural waves from the anisotropic formations is attempted by treating the formation as being isotropic. Corrections of the slow shear waves are less satisfactory.
Interesting relations among unipole, dipole, and quadrupole also are revealed from a large-borehole scenario. The models confirm that in a large borehole with excessive tool eccentricity, both dipole and quadrupole responses may approach that of a unipole tool as some of the dipole and quadrupole excitation and reception sectors lose their proximity to the borehole wall. The modeling also shows that the dispersion effect in a unipole wave will be dependent on tool standoff, implying the necessity of standoff measurement for accurate dispersion corrections.
Reservoir Surveillance - Fluid Contact Monitoring in Fractured Carbonate TA-GOGD Project
Authors: Edwards John , Brown George , Vincent Mark , Keshishian Avo , Putra Pristiwanto , Bettembourg Solenn 
Published: October 2011

Abstract
TA-GOGD is suited for heavy oil in fractured formations. Steam is injected into the fractures serving two purposes; applying a gas gradient across the carbonate blocks so that the oil in the carbonate drops down by gravity, and heating the carbonate blocks so that the reduced viscosity oil drips out faster. The reservoir has two fluid systems; gas/oil/water levels in the fractures, and gas/oil/water contacts in the carbonate. Oil extracted from the carbonate accumulates in the fractured oil rim, where it is produced by wells intersecting the fractures. It is essential to manage the oil rim position and thickness. Wireline interventions with gradio manometer are not safe where steam is injected at 55 bars and 271°C. This temperature is too hot for permanent electronic gauges, but is within the operating range of optic fiber used to measure distributed temperature.
A new measurement to determine the fluid levels was developed using differential thermal relaxation. Cold water was pumped around a U tube containing an optic fiber and clamped outside the perforated tubing across the open hole until the temperature at the reservoir depth inside this U tube was considerably less than the hot surrounding gas, oil and water. With the pump stopped, the rate at which the cooler water inside this U tube reached thermal equilibrium with the warmer well bore fluids was measured with rapidly repeated distributed temperature surveys. Gas, oil and water have different specific heat capacities and thermal conductivities, so each surrounding fluid took a different length of time to heat the cooler water inside the U tube. The differences caused sharp discontinuities on the initial temperature logs of the warming water inside the U tube at the depths of the fluid contacts. The fluid levels measured with this method are sufficiently accurate to manage the oil rim.