bluuebunny/crossref_metadata_2025_split huggingface dataset:
How Significant Is the P90 Value as a Measure of the Reserves' Downside?
Authors: Gupta S.. , Gupta R.. , van Elk J.F.. F. , Vijayan K.. 
Published: June 2014

Summary
Probabilistic methods for reserves estimation, including uncertainty quantification and probabilistic aggregation, have gained widespread acceptance in the oil and gas industry, since the first comprehensive guidelines were issued by the Society of Petroleum Engineers (SPE) (Swinkels 2001). The probabilistic methods now used in the oil industry, as proposed in these guidelines, are similar to those also used in portfolio theory and risk management by the finance industry. A significant amount can be learned from the extensive experience with probabilistic methods and quantification of risk with measures like value-at-risk (VAR), in financial risk management. Especially, the guidelines issued by the Basel II Accord (Bank for International Settlements 2006) and the discussions since the 2008 financial crisis contain important lessons.
In this paper, we examine a fundamental question: "Is the P90 reserves value an appropriate measure for quantifying the reserves’ downside?" For the P90 reserves value to be considered a good measure of the reserves’ downside, it needs to possess a number of basic characteristics involving P90 reserves for each field and the probabilistically aggregated P90 reserves for the portfolio of fields. Analogous to the definition of a coherent risk measure used in the finance industry, we define these characteristics for P90 reserves.
The P90 reserves are as good a risk measure as VAR used in the financial industry. However, like VAR, it is not a coherent risk measure. A possible uncertainty scenario, in which one of these necessary characteristics does not hold, is given. An alternative measure of risk for quantifying the reserves’ downside, defined as the average reserves over the confidence interval higher than P90, is presented. This is a coherent risk measure.
In this paper, we highlight the appropriateness and limitations of using the P90 reserves estimate as a measure of the reserves’ downside. Understanding of the limitations posed by using the P90 reserves value is vital in management of reserves risk.
Simplified Forecasting of Tight/Shale-Gas Production in Linear Flow
Authors: Nobakht Morteza , Mattar Louis , Moghadam Samane , Anderson David Mark 
Published: June 2014

Summary
This paper presents a simplified method of production forecasting for tight/shale-gas reservoirs exhibiting extended periods of linear flow, without the use of complex tools (e.g., analytical models or numerical models). The method, which is applicable to hydraulically fractured vertical wells and multifractured horizontal wells, is simple because it relies principally on a plot of inverse rate vs. square root of time, and it is rigorous in that it is based on the theory of linear flow and combines the transient linear-flow period with hyperbolic decline during boundary-dominated flow.
The dominant flow regime observed in most tight/shale-gas wells is linear flow, which may continue for several years. This linear flow will be followed by boundary-dominated flow at later times. Therefore, the method proposed in this study is applicable for forecasting production data for these wells because it considers these two important flow regimes. The derivation is presented for a hydraulically fractured well, and this simplified method can be applied both to hydraulically fractured vertical wells and to horizontal wells with multiple fractures. The application of this method to multifractured horizontal wells in the Marcellus and Barnett shale gas is also presented.
The method is validated by comparing its results with test cases, which are built using numerical simulation for hydraulically fractured vertical wells. For each case, only the first year of the synthetic production data is then used for the analysis. It is found that there is reasonable agreement between the forecast rates obtained using this method and the numerically simulated rates.
Currently, analysis techniques using material-balance time are being used in industry to analyze tight/shale-gas reservoirs. Because material-balance time is actually boundary-dominated flow superposition time, these analyses may show symptoms of boundary-dominated flow even though the reservoir is still in transient flow. The advantages of the forecasting method proposed in this study are that: (1) it is not biased toward any flow regimes because no superposition time functions are used; (2) reliable forecasts can be obtained without using pseudotime--this is an advantage because using pseudotime introduces complexities and an iterative procedure; and (3) the only major unknown is the drainage area.
Application of Optimizing Techniques for Studying Field Producing Operations
Authors: Attra H.D. , Wise W.B. , Black W.M. 
Published: June 2014

Abstract
The purpose of this paper is to illustrate a comparatively new approach for solving a problem that has plagued oil producers for many years-how to make the most money with available field production capacity.
In a very basic operation such as a top-allowable one-well field, a computer and staff of engineers are not required to determine that the best operation is to produce that well at its maximum for as long a time as it will produce. However, as, the problem becomes more complex and the number of wells and number of reservoirs increase, it probably will be a wise choice to devote some engineering thought and calculation time to determine the best way to operate that field on both an ultimate and day-to-day basis.
Continued developments in the field broadly referred to as "operations research" have led to a number of useful engineering analyses for optimizing field operational problems. One of these techniques, termed linear programing, is particularly interesting because of its potential applications to the study of complex oilfield operating problems. Linear programing is concerned with the problem of planning a complex set of interdependent activities in the best possible (optimal) fashion.
A field application of linear programing is being used to maximize daily income from a multi-reservoir producing operation. The initial results of this study indicate that the linear programing techniquecan be applied effectively to field problems,can be used to detect unsuspected avenues for improving operations andcan effect a significantly improved means of controlling field operations through the use of the high-speed computer.
Enhanced Technology Transfer for Geothermal Exploitation Through a New Research Concept: The Geothermal Energy and High-Performance Drilling Research Program: gebo
Authors: Reinicke K. M. , Oppelt J. , Ostermeyer G. P. , Overmeyer L. , Teodoriu C. , Thomas R. 
Published: June 2014

Abstract
The government of Lower Saxony plans an extensive utilization of the geothermal potential in its subsurface for heat and electrical energy supply. The conditions to achieve this objective are quite favorable despite the moderate temperatures typical for the subsurface here: the geothermal potential below the surface of Lower Saxony is considerable, the knowledge of the geological subsurface in this oil and gas federal state is good, and the scientific and industrial infrastructure for exploring and developing the geologic subsurface is excellent.
The gebo research association unites the traditional strengths of the participating universities of the federal state of Lower Saxony and independent research institutions in geosciences, drilling technology, materials science, and technical systems. More than 40 scientists and engineers work together to develop and evaluate new concepts, materials, and devices. The gebo research association focuses on broad-scale, partially extremely high-risk problems in the "high-end" area of geothermal research; at the same time the participating industry is carrying out applied systems developments. Besides improving the economics of geothermal energy production and making it economically attractive in Lower Saxony, significant gebo "spinoff’ effects are expected to occur in industrial sectors, in particular from the materials and systems technology research.
The paper focuses on the concept of technology transfer through the gebo platform, as well as on its unique cooperation between seven project partners (research institutions), the industry partner, and the state of Lower Saxony. Also, the paper describes the objective, strategy, and organization of the research program gebo, which aims at improving the economics of geothermal energy recovery from deep geological strata by investigating new concepts and basic scientific work.
Methodology for Estimating Recovered Solvent in Solvent-Aided Process
Authors: Gupta Subodh C. , Gittins Simon , Canas Christian 
Published: June 2014

Summary
The solvent-aided process (SAP) is a solvent-based enhancement of steam-assisted gravity drainage (SAGD) in which small amounts of solvent, such as light alkanes or natural-gas liquids, are added to the injected steam to enhance reservoir performance and associated project economics. Expectedly, the economics with SAP are sensitive to the solvent recovered from the reservoir, making its measurement in a field test an important factor.
When a single-component solvent such as butane, which is not generally present in the produced heavy oil or bitumen, is used in SAP, estimation of the recovered solvent can be achieved uniquely. But when the solvent also has heavier components, some of which overlap with the lighter components of the produced oil, the measurement is not straightforward. The problem is compounded by the fact that the interaction with the reservoir changes the composition of the produced solvent and makes it time variant on account of different resident times associated with different components. The issue is further complicated by the fact that produced oil also undergoes an in-situ solvent deasphalting process (SDA), which is also time and space variant in the reservoir. If there were no in-situ SDA, one potential method to measure the amount of produced solvent would be to measure the total asphaltene content as an oil "marker" in the produced blend. Use of a tracer with injected solvent, as well as regression-based analyses for solvent fraction (using compositional analyses of solvent, bitumen, and the blend) of the produced blend, is error prone for these same reasons.
Because of the issues in these approaches, a new method is desirable for a more-robust and unique assessment of the solvent amount in the produced fluids. This paper elaborates on the current challenges and proposes a couple of workable methods, including use of maltenes/metals content as oil markers as well as the use of boiling-point curves of the produced blend compared with the boiling point of the base oil.
Such techniques of estimating the recovered solvent can facilitate a more-objective assessment of SAP field tests and enable economic evaluation of SAP application to a commercial scale.
Foamy-Oil-Viscosity Measurement
Authors: Alshmakhy Ahmed , Maini Brij B. 
Published: June 2014

Summary
Foamy-oil viscosity is a controversial topic among researchers regarding what happens to the oil viscosity when the solution gas starts coming out of solution because of decreasing pressure and the released gas starts migrating with the oil in the form of dispersed gas bubbles. For conventional oils, below the true bubblepoint pressure, the oil viscosity increases as the gas freely evolves from the oil. For foamy oils, it has been suggested that the apparent oil viscosity remains relatively constant or perhaps declines slightly between the true bubblepoint and a characteristic lower pressure, called pseudobubblepoint, which is the pressure at which the gas starts separating from the oil. Below this pressure, the viscosity increases, reaching the dead-oil value at atmospheric pressure. However, it is a well-known fact in dispersion rheology that the viscosity of dispersion is higher than the viscosity of the continuous phase. Therefore, the concept of foamy-oil viscosity being lower than the oil viscosity is counterintuitive. It is likely that the apparent viscosity for flow of foamy oil in porous media is not the true dispersion viscosity because of the size of dispersed bubbles being comparable to the pore sizes.
This study investigates this issue by measuring the foamy-oil viscosity under varied conditions. The effect of several parameters, such as flow rate, gas volume fraction, and type of viscometer employed, on foamy-oil viscosity was evaluated experimentally. Three different viscosity-measurement techniques, including Cambridge falling-needle viscometer, capillary tube, and a slimtube packed with sand, were used to measure the apparent viscosity of gas-in-oil dispersions. The results show that the type of measuring device used has a significant effect. The results obtained with Cambridge falling-needle viscometer correlate better with the observed behaviour in the sand-packed slimtube than the capillary viscometer results. Overall, the apparent viscosity of foamy oil was found to be similar to live-oil viscosity for a range of gas volume fractions.
Multioriented Fracturing in Unconventional Reservoirs Offers Improved Production by Better Connectivity
Authors: Surjaatmadja Jim B. 
Published: June 2014

Summary
In the oil field, the term "unconventional" almost always means difficult to obtain for one or another reason. One reason addressed in this paper relates to formations characterized by the lack of permeable features that connect or can be easily connected to the wellbore using conventional stimulation techniques. The common logic of placing larger and larger fractures does work, but, when using this approach, the cost-to-reward ratio can be far from desirable.
It is well known that placing a second fracture sometime later in the life of a well will result in a fracture that extends in a slightly different direction, mostly caused by the drainage of the fluid near the fracture face. In this situation, fracture redirection is probably caused by the pore-pressure decline near the producing fracture face. In some instances, the new fracture produces almost as if it has reached a new formation.
This paper discusses placement of such second (or third) hydraulic fractures within the same time domain from the same wellbore section. While this has not yet been performed in the field, it is believed that the first fracture will modify the stress field to a perpendicular direction. Combined with the hypothesis of the hard-to-accept concept that fractures often shy away from the most-productive zones, this approach will cause the second fracture to extend directly into the more-productive zones, thus providing a substantial production boost.
Experimental Evaluation of SAGD/ISC Hybrid Recovery Method
Authors: Paitakhti Oskouei Seyed Javad , Maini Brij B. , Moore R. Gordon , Mehta Sudarshan A. 
Published: June 2014

Summary
Most current in-situ recovery methods have limitations which restrict their application in many heavy-oil reservoirs. There is also a variety of undesirable environmental issues associated with existing thermal-recovery techniques. To overcome some of these problems, novel hybrid processes have been proposed that combine steam-assisted gravity drainage (SAGD) and in-situ-combustion (ISC) technologies. In the conventional ISC process, oil is displaced by an elevated-temperature combustion zone, but when the native oil mobility is low, this displacement becomes problematic because of the low oil mobility downstream of the combustion front. Heating the reservoir and reducing the distance between injector and producer can prevent such cold liquid blocking in the combustion process. This suggests that a well configuration that greatly decreases the distance between the injector and the producer (e.g., the SAGD well configuration) could be advantageous in ISC-based recovery methods. Moreover, running the SAGD operation in the initial period creates a vapour-filled depleted zone in the reservoir that would be sufficiently hot to start combustion on air injection. To investigate the feasibility of this idea, a hybrid experiment was conducted at a representative reservoir pressure. During the experiment, SAGD was operated in a physical model for a period and then combustion was started by switching from steam injection to air injection. A modified well arrangement was used to help the process operation, oil ignition, and combustion-front formation. Residual oil and water saturations in the model were analyzed. Also, core samples were extracted from the model to evaluate asphaltenes and coke formation. It was shown that it may be possible to recover nearly 70% of the original oil in place with a modified well arrangement.
Measuring the Reaction Rate of Lactic Acid With Calcite and Dolomite by Use of the Rotating-Disk Apparatus
Authors: Rabie Ahmed I. , Shedd Daniel C. , Nasr-El-Din Hisham A. 
Published: June 2014

Summary
Lactic acid has been examined in various laboratories and applied in the oil field for acid fracturing and drilling-fluid-filter-cake removal, and as an iron-control agent during acid treatments. However, the reaction of lactic acid with calcite has not been addressed before. Determination of the reaction rate and the acid-diffusion properties is a critical step for successful treatments in matrix acidizing and acid fracturing. Therefore, the objective of this work is to conduct a detailed study on the reaction of lactic acid with calcite. Mass transfer and reaction kinetics are reported for the lactic acid/calcite system by use of the rotating-disk apparatus.
Disk samples were cut from Indiana limestone or Silurian dolomite and were used in the reaction-rate experiments. The effect of lactic acid concentration (1, 5, and 10 wt%), temperature (80–250°F), disk rotational speed (100–1,800 rev/min), and different inorganic salts on the reaction rate was investigated. The diffusion coefficient of 5 wt% lactic acid was determined at low disk rotational speeds and reported at 80, 200, and 250°F. A model that accounts for the effect of the kinetics of the surface reactions and the transport of reactants and products was developed. The activation energy and the rate constant at 80, 150, and 250°F for the reaction of lactic acid with Indiana limestone were reported. Reaction experiments of lactic acid with dolomite at 150°F over disk rotational speeds of 100–1,800 rev/min, and at 1,500 rev/min over a temperature range of 80–250°F, were conducted and the results were compared with those obtained for the calcite reaction.
At 80°F, the reaction of lactic acid with calcite was controlled by mass transfer at low disk rotational speeds (up to 500 rev/min) and was surface reaction limited at higher speeds. At higher temperatures (150, 200, and 250°F), both mass transfer and surface reaction influence the overall calcite dissolution. The kinetics of the surface reaction were influenced by both forward and backward reactions. At 80°F, the surface reaction contributes to 28% of the overall resistance. This dependence becomes much less (13 and 10%) at higher temperatures (150 and 250°F, respectively).
The reaction of lactic acid with dolomite at 150°F was mainly controlled by mass transfer up to 1,000 rev/min and by the kinetics of the surface reaction after 1,000 rev/min. At 80 and 150°F, the rate of reaction of lactic acid with calcite was an order of magnitude higher than that with dolomite. At temperatures of 200 and 250°F, the rate of reaction of lactic acid with calcite is twice the rate of reaction with dolomite. The presence of Ca2+, Mg2+, and SO42− ions reduced the reaction rate, which is most likely because of the reduction in the concentration gradient of the products. The reduction in the concentration gradient will cause a reduction in the rate of diffusion of the generated calcium away from the surface, and hence a lower rate of dissolution.
The Potential Pitfalls of Using North American Tight and Shale Gas Development Techniques in the North African and Middle Eastern Environments
Authors: Martin A.N.. N. 
Published: June 2014

Summary
Many companies operating in the upstream gas industry in the Middle East and North Africa (MENA) are interested in the outstanding technical successes achieved by the US and Canadian tight and shale gas producers. It seems almost miraculous that companies can obtain significant gas-production rates from rocks with permeabilities measured in nanodarcies—so low, in fact, that permeability becomes almost impossible to assess accurately. In North America, the main factor now constraining shale gas production is the historically low gas price. Operators in MENA, who are accustomed to working in formations with permeabilities five or six orders of magnitude greater, have realized recently that they may be sitting on top of huge untapped gas reserves that had been evaluated previously as subeconomic.
In recent years, several major MENA-based operating companies have bought interests in US and Canadian tight and shale gas operations, with the objective of acquiring experience and technology that can be applied to similar formations in MENA and elsewhere. This seems to be an obvious and wise strategy; unfortunately, the problem is not the strategy, it is the tactics ("the devil is in the details"). In many instances, operating companies have been disappointed to discover that they cannot simply transplant an American-style development into MENA. Similarly, many North American independents have viewed the untapped low-permeability gas reserves of MENA as a natural territory for expansion, only to find themselves frustrated at almost every turn.
This paper seeks to highlight the potential pitfalls of trying to use North American development techniques in MENA, and to promote strategies and tactics that are more suitable. In addition, this paper will suggest structural changes that could have a significant positive impact on low-permeability gas developments in MENA.
A Numerical Study of Microscale Flow Behavior in Tight Gas and Shale Gas Reservoir Systems
Authors: Freeman C. M. 
Published: June 2014

Abstract
Tight gas and shale gas represent a significant energy resource. These types of reservoirs are geologically complex and the reservoir flow processes involved are unusual. While some investigators have modeled various aspects of these systems, there is currently no consensus on the significance of microscale diffusion on flow behavior over time. Pore throat diameters on the order of nanometers are known to result in non-Darcy flow conditions, which can be accounted for using the dusty-gas model coupled with various models for diffusivity estimation. This phenomenon is related to the Klinkenberg effect.
In this work we implement the dusty-gas model into a reservoir modeling tool based on the TOUGH+ code. We examine the effects of Knudsen diffusion on flowing gas composition at low permeability. We show that for rock with small pore throat diameters, the composition of flowing gas is significantly different than the in situ stagnant conditions. We describe how gas composition measurement could be used to identify flow boundaries in these reservoir systems. We present a fit-for-purpose numerical model based on the TOUGH+ code for modeling microscale transport effects.
This work contributes:
A new multicomponent microscale transport model A new, fit-for-purpose numerical model based on the TOUGH+ code capable of characterizing reservoir flow effects including permeability adjustment and diffusion in micro- and nano-scale porous media.