bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geochemical Oil Fingerprinting – Implications for Production Allocations at Prudhoe Bay Field, Alaska
Authors: Schafer Daniel , Bommarito Olivia , Cooper Katrina , McCaffrey Mark , Meixueiro Paulina , Mower Matt 
Published: October 2011

Abstract
The Prudhoe Bay Field has been producing for more than 30 years with the majority of the production derived from the Ivishak sandstone, and a lesser amount coming from the structurally shallower and stratigraphically younger Sag River sandstone. The reservoir properties of the Sag River are dramatically lower quality than those of the Ivishak with respect to thickness, porosity, permeability, and deliverability. The far superior Ivishak dominates total flow into the wellbore when commingled completions exist; however, since total flow is the sum of oil plus water, the Ivishak does not necessarily dominate oil production in any given well. Within individual wells, proper allocation of commingled production from the Ivishak and Sag River is necessary for well optimization, but such allocation can present a technical challenge. Production logging (PPROF) can assist in production allocation; however, production logging is very costly, sometimes yields ambiguous or even erroneous results, and causes the well to be shut-in while logging setup occurs resulting in deferred production. Geochemistry-based allocation of commingled production (i.e., oil fingerprinting) is far less expensive (~1% the cost of production logging) and is proving to be very reliable for zonal allocations where Sag River and Ivishak perforations exist. The successful application of the geochemical allocation method relies on the availability of pure Sag River and Ivishak "end-member" oils from nearby wells to form the calibration standards for the geochemical methodology. This paper presents examples of the success and limitations encountered while attempting to implement this cost-effective geochemical allocation method.
New Cold Production Technique for Heavy Oil with Strong Bottom Water Drive
Authors: Qin Wenting , Wojtanowicz Andrew K. , White Christopher D. 
Published: October 2011

Abstract
Few heavy oil reservoirs with strong bottom water drives have been developed successfully, because severe water coning causes low ultimate recovery, low well productivity, and high water production. In these reservoirs, thermal and gravity-assisted methods that could improve recovery are perceived economically unfavorable or technologically infeasible. In this paper, we propose a new cold production technique, called Bilateral Water Sink (BWS), to meet those challenges.
The BWS method suppresses water cresting by producing oil and water simultaneously from bilateral horizontal wells completed in the oil and water zones separately. Unlike conventional horizontal well production, where water crest cause water to bypass oil, making the water drive mechanism ineffective; BWS prevents water cresting by altering the potential distribution in the near-well area. With cresting suppressed, the top lateral well's production stream is water-free, and water drives the oil from the edges of the well drainage area to the well, resulting in high ultimate recovery. By exploiting the natural reservoir energy of the bottom water drive, BWS becomes economically, technically, and environmentally appealing – especially for offshore where cold production is the only option and oil-water separation is a problem.
In this paper, new analytical models are derived to design the water and oil rates for BWS and to quantify the BWS's effect of avoiding water cresting and improving oil recovery. The analytical models are verified with numerical simulations. The BWS technique is also theoretically demonstrated using data from actual oilfield. The results show a considerable increase of oil recovery from less than 15 percent for conventional horizontal well to over 40 percent for BWS well.
What Does Microseismicity Tell Us About Hydraulic Fracturing?
Authors: Maxwell S. C. , Cipolla C. 
Published: October 2011

Abstract
Interpreting hydraulic fracture geometry isn't the only proven value application of microseismic imaging. With careful geophysical analysis, the microseismic deformation can also be determined in terms of the fracture strain that results in the source of the observed microseismic signals. The microseismic strain or deformation is potentially of interest, since the deformation associated with the hydraulic fracture controls the fracture dilation and complexity and ultimately the effectiveness of the stimulation. However, evidence is presented here which points to the microseismic being primarily a fast, shearing deformation in contrast to the relatively slow and tensile hydraulic fracture growth. Comparing the deformation energy balance between the recorded microseismic and the hydraulic fracture indicates that the microseismic is a very small component of total deformation. The majority of the fracture deformation is aseismic, beyond what is captured with conventional microseismic monitoring.
The microseismic and hydraulic fracture deformations can be rationalized through a geomechanical model that honors the fracture mechanics and mass balance to simulate fracture growth. A workflow is presented that describes calibrating a geomechanical model using the location, timing and strains of the recorded microseismic to match the modeled interaction between the hydraulic fracture and pre-existing fractures. A rock physics model is also required to define synthetic microseismic data from the geomechanical model, for comparison with the observed microseismic data. The simplest form of calibration is a qualitative match between the relative microseismic density of either number of events or source strength. However, more advanced quantitative matches can also be made between the simulated and monitored microseismicity, by matching the microseismic displacements and mechanisms with the additional constraint of matching the energy balance. Through such a calibrated geomechanical model, the interrelation between stress, fractures, and injected fluid can be examined and used to characterize the hydraulic fracture growth. The validated hydraulic fracture model can then be incorporated into a reservoir simulator to ultimately predict the associated production characteristics. Therefore, beyond hydraulic fracture geometry, microseismic source deformation can be used to constrain a geomechanical model of the hydraulic fracture growth and thereby help describe the overall effectiveness of the stimulation.
Gas Permeability of Shale
Authors: Sakhaee-Pour A. , Bryant Steven L. 
Published: October 2011

Abstract
The permeability is one of the most fundamental properties of any reservoir rock required for modeling hydrocarbon production. However, the shale permeability has not yet been fully understood because of the complexities involved in modeling flow through nanoscale throats. Here, we analyze the effects of adsorbed layers of CH4 and of gas slippage at pore walls on the flow behavior in individual conduits of simple geometry and in networks of such conduits. The network is based on the scanning electron microscopy image and drainage experiment of shale. To represent the effect of adsorbed gas, the effective size of each throat in the network depends on the pressure. The hydraulic conductance of each throat is determined based on the Knudsen number (Kn) criterion. The combined effects of adsorption and slip depend strongly on pressure and on conduit diameter. The results indicate that laboratory measurements made with N2 at ambient temperature and 5 MPa pressure, which is typical for transient pulse decay method, overestimate the gas permeability at early life of production by a factor of 5. This ratio increases if the measurement is run at ambient condition since the low pressure enhances the slippage and reduces the thickness of adsorbed layer. Moreover, the permeability increases nonlinearly as the in-situ pressure decreases during production. This effect contributes to mitigating the decline in production rate of shale gas wells.
Use of Pickett Plots for Evaluation of Shale Gas Formations
Authors: Yu Guang , Aguilera Roberto 
Published: October 2011

Abstract
A practical method, based on the pattern recognition approach used in Pickett plots, is presented for preliminary yet accurate quantitative evaluation of shale gas formations. The method is inspired by a quick-evaluation, time-tested methodology developed by Passey et al. (1990) for shales, which utilizes primarily sonic and resistivity logs. In Passey et al. method the sonic and resistivity logs are overlain in such a way that the curves track each other in fine-grained non-source rocks. Separation of the curves indicates the presence of organic-rich intervals.
The Pickett method presented in this study reproduces data published by Passey et al. with coefficients of determination (R2) greater than 0.99 for cases related to sandstones, limestones, dolomites and shales. As Pickett plots have been used thousands of times in the past for evaluation of the first 3 mentioned lithologies, this paper concentrates primarily on the evaluation of shale gas reservoirs. The advantage of the proposed Pickett plot for shale gas formations is that it allows quick estimates of water saturation, total organic carbon, and under favorable conditions, estimates of fracture intensity and diffusion. The objective of the proposed approximate approach, however, is not to replace detailed petrophysical and thermal maturity studies but to provide quick and accurate evaluations of shale gas formations.
It is concluded that Pickett plots provide a powerful practical tool for quick evaluation of shale gas formations. Examples of applications and comparisons with previously published interpretations are presented in detail.
Impact of Reservoir Permeability on Flowing Sandface Temperatures; Dimensionless Analysis
Authors: App J. F. , Yoshioka K. 
Published: October 2011

Abstract
Layer flow contributions are increasingly being quantified through the analysis of measured sandface flowing temperatures. It is commonly known that the maximum temperature change is affected by the magnitude of the drawdown and the Joule-Thomson expansion coefficient of the fluid. Another parameter which strongly impacts layer sandface flowing temperatures is the layer permeability. Aside from determining the drawdown, the layer permeability also affects the ratio of heat transfer by convection to conduction within a reservoir. The impact of permeability can be represented by the Peclet number, which is a dimensionless quantity representing the ratio of heat transfer by convection to conduction. The Peclet number is directly proportional to reservoir permeability. Through dimensionless analysis it will be shown that for a given drawdown (based on a dimensionless Joule-Thomson expansion coefficient, JTD) the temperature change diminishes at low Peclet numbers and increases at high Peclet numbers. This implies that for low permeability reservoirs such as shale gas or tight oil, the temperature changes will be minimal (less than 0.1 °F) despite the large drawdowns in many instances. Dimensionless analysis is performed for both steady-state and transient thermal models. Results from multi-layer, transient simulations illustrate the ability to identify contrasting permeability layers based upon the Peclet number effect.
An Integrated Workflow for Reservoir Modeling and Flow Simulation of the Nikanassin Tight Gas Reservoir in the Western Canada Sedimentary Basin
Authors: Deng Hui , Aguilera Roberto , Settari Antonin 
Published: October 2011

Abstract
This paper presents an innovative workflow for characterization and reservoir simulation of the tight gas Nikanassin Group in the Western Canada Sedimentary Basin. Petrographic studies of the Nikanassin Group show the presence of (1) intergranular, (2) microfracture + slot, and (3) isolated (non effective) porosities. These porosities are handled with a mathematical triple porosity model for improved petrophysical analysis of the Nikanassin Group. Determination of pore throat apertures (rp35) facilitates facies mapping for reservoir simulation purposes. Numerical well testing of hydraulically fractured wells provides a way of tuning the static model with dynamic well testing information. In the case of open uncemented fractures and slots, numerical well testing indicates that the reduction of in-situ permeability can be more than two orders of magnitude. On the other hand in the case of partially cemented fractures and slots the reduction in permeability might be negligible. The approach permits an efficient representation of hydraulic fractures using transmissibility multipliers for the full field simulation of commingled tight reservoirs with multi-wells and multi-stage fractures.
The result is a sound full field simulation model that permits a reasonable match of production and pressure histories, and forecasting of gas recovery under different well-spacing and depletion scenarios. As most Nikanassin tight gas wells are completed commingled, this research develops a procedure for production allocation of individual contributing formations.
The study shows that there is a very large gas potential in the Nikanassin Group, particularly in the Lower Monteith Formation that can be exploited by reducing significantly the well spacing. The finding is significant as the tight gas Nikanassin Group extends for more than 15,000 km2 within Alberta and British Columbia, which suggests the potential for drilling thousands of wells in the region.
Stability Analysis of Pipe with Connectors in Horizontal Wells
Authors: Gao Guohua , Di Qinfeng , Miska Stefan , Wang Wenchang 
Published: October 2011

Abstract
Except for coiled tubing, most tubular goods used for down-hole operations such as drilling pipe and sucker rod have connectors. Since a connector and the pipe-body have different outer radius, the deformation and buckling behavior of a pipe with connectors constrained in a wellbore are much more complicated. However, most buckling models were established by neglecting the existence and effects of connectors.
In this paper, buckling equations of a pipe with connectors in horizontal wells were derived with application of elastic beam theory. The axis of an unbuckled pipe is a 2-D curve in the vertical plane, and has three configurations: no contact, point contact and wrap contact. We derived the two critical distances between connectors, Lc1 and Lc2, beyond which a pipe changes its configuration from one to another. The authors proposed an algorithm to determine the critical force (Fcrs) of buckling by numerically solving the buckling equations using the 4th order Ronge-Kuta method.
Both the distance between two adjacent connectors (Lc) and the radius difference between a connector and the pipe-body (Δrc) have significant impact on the critical force, in addition to net clearance between a pipe and wellbore (r0), bending stiffness (EI) and weight per unit length (w) of pipe. When Lc is small, radial deflection is negligible. Fcrs increases as Δrc increases. However, when Lc is close to Lc1, effects of radial displacement become significant, and Fc decreases dramatically as Δrc increases. Fcrs decreases as Lc increases when Lc&lt; Lc1, and it reaches its minimum at Lc=Lc1. When Lc&gt; Lc1, Fcrs fluctuates as Lc increases. Some curves of Lc1, Lc2 and Fcrs, all in dimensionless forms, were calculated and presented in this paper for practical applications.
Our numerical results show that the critical force may reduce 20-60% for commonly used drill pipes and sucker rods with centralizers, which indicates that a pipe string designed without considering the effects of connectors may be risky. The results presented in this paper may provide some practical guidance for optimal design of centralizers for sucker rod strings, or may avoid some risks due to improper design of drilling pipe strings.
Quantitative Integration of Flow Simulation and 4D Multi-Component Seismic in a CO2 WAG EOR Project
Authors: Heris A. E. , Wandler A. , Kazemi H. , Davis T. L. 
Published: October 2011

Abstract
In management of mature oil fields for enhanced oil recovery, 4D seismic imaging plays a very important role. Previously, we published the qualitative results of integrating flow simulation with time-lapse multi-component seismic data for a CO2 EOR project in the thin valley-fill Morrow formation at Postle Field. In this paper, we will present our quantitative approach and results from integrating flow simulation with time-lapse seismic.
Three seismic surveys have been acquired at Postle Field to monitor the ongoing CO2 flood. Since presentation of the previous paper, additional seismic and production data has become available which has influenced both the history match of the reservoir flow model and seismic interpretation. Gassmann's fluid substitution method was used to relate the flow simulation results with time-lapse seismic attributes. In addition, a sensitivity analysis was performed using a conceptual model to investigate the effect of various reservoir dynamic parameters on seismic response.
Flow simulation and rock physics modeling show that production and injection in the reservoir causes saturation and pressure changes, which affect acoustic and elastic properties of the reservoir. Acoustic impedance calculated from the simulation model was compared to the corresponding results from seismic data. The magnitude of changes of acoustic impedance calculated from the flow simulation is similar in range to that from seismic inversion. The effect of fluid saturation change in the reservoir, particularly CO2 saturation, is greater than the effect of pressure change. Conceptual modeling indicates that the sensitivity of seismic attributes to changes in CO2 saturation and water saturation is weak and may be difficult to detect seismically. On the other hand, to have a relatively big change in acoustic impedance, a big change in pressure is needed.
Our research results demonstrate that for a credible dynamic reservoir characterization, an integration of flow simulation and 4D seismic is required which, in turn, could be a viable method to guide field operations. However, this process is challenging in thin reservoirs undergoing CO2 WAG injection.
Geographic Response Strategy "An Integrated System for Effective Spill Response"
Authors: Ayu Sito Mirah , Rusjanto Juli , Sarwanto Puguh , Hidayatullah Hidayatullah , Prasetyo Romy Irvan 
Published: October 2011

Abstract
A continuous improvement in dealing with hydrocarbon spill in Mahakam Delta is important due to the rapid change and more stakeholders in the area. Geographic Response Strategy (GRS) can answer the challenge to help spill responder in decision making by providing integrated essential information in one tool.
During emergency response operations, the available information may be highly uncertain, especially the initial information in the early stages of the emergency situation. This condition requires the emergency response team to ascertain what is actually known about the emergency situation, assess and select the best strategy to respond to the situation as soon and as effectively as possible. Appropriate strategy is very essential in order to minimize the overall consequences on people, environment, asset and company reputation.
GRS ensures that Main Emergency Control Cell (ECC), Site ECC and field responder are in the same perspective during spill response. Main ECC and Site ECC able to access information and strategy guideline in the GRS through intranet while field responder able to perform response strategy accurately using Field Responder Map.
Essential information which are integrated in the GRS covering Total E&P Indonesie facilities, pipeline inventory, emergency shutdown valve (ESDV) location, emergency equipment at site, sensitive area location, hazard location, spill response guideline, hydrodynamic 3D modeling, and automatic vessel tracking system. GRS implementation offer solution for making decision within tight timeline. It can help in prioritizing action; protect sensitive area, which at the end will reduce safety risk, environmental impact and cost associated with the impact.
From the Classroom to the Field: Learning Transfer Strategies
Authors: Wakefield Sarah , Murdock Patty , Pigusch Katrina 
Published: October 2011

Abstract
"What does this have to do with the real world?" These words sometimes thought by students in the academic world should never go unanswered by technical training classes in the corporate world. In the competitive business environment of today, at a time when mistakes on the job cost a premium, the industry needs technical training that effectively makes the leap from the classroom to the job. Valid strategies for classroom learning transfer do exist. Classroom training must be made relevant to the workplace. This can be accomplished, for example, by providing context, building new information based upon old information using realistic exercises and simulations, applying memory techniques and referring to specific questioning techniques that relate classroom information to the job. In this paper, the research behind learning transfer as well as specific technical oilfield examples will be discussed. This information is relevant to industry professionals who wish to facilitate an effective learning transfer from the classroom to the field.
Heat Transfer Applications for the Stimulated Reservoir Volume
Authors: Thoram Srikanth , Ehlig-Economides Christine 
Published: October 2011

Abstract
Multistage hydraulic fracturing of horizontal wells enables creation of a Stimulated Reservoir Volume (SRV). An idealization of the SRV for shale gas production is a rectangle of length equal to horizontal well length and width equal to twice the half length of the created hydraulic fractures. This paper discusses the use of an analogous SRV design for two novel thermal applications.
The first application considers using the SRV of a shale gas well, after the gas production rate drops below the economic limit, for low grade geothermal heat extraction. Cold water is pumped into the fracture network through one horizontal well drilled at the fracture tips. The water is heated by contact with the hot rock, and then recovered through a second horizontal well drilled at the other end of the fracture network. The basis of this concept is to use the already created stimulated reservoir volume for heat transfer purposes. Technical and economic feasibility of applying this technique to Haynesville Shale are evaluated.
The second application considers using a similarly created SRV for producing oil from oil shale. Thermal decomposition of kerogen to oil and gas requires heating the oil shale to 700°F. We propose to inject high quality saturated steam generated using a small scale nuclear plant for heating the formation to the necessary temperature. Using the same flow geometry as in the previous case, produced water would be reheated and reinjected in a closed cycle. The energy required for steam heating is compared to other approaches in the literature.
Analytical and numerical models are developed to evaluate the number, dimensions, and spacing of fractures sufficient to achieve heat transfer in a reasonable length of time for each of these applications.