bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case History: Acid Fracturing Deep, Hot Ellenburger
Authors: Swain Michael , Nordstog Kim , Miller Howard , Fallon James , Weaver Bob , Metcalf Arthur S. 
Published: December 2007

Abstract
In Val Verde and Crockett counties of Texas, operators are drilling 15,000 feet plus wells to produce the Ellenburger formation. Bottomhole Static Temperatures are in the neighborhood of 320°F. Since the Ellenburger is a massive dolomite formation with natural fractures the optimum stimulation method is acid fracturing.
Discussed are the critical issues to achieve a successful stimulation using acid at plus 300°F. In addition, techniques employed will be reviewed. One technique is stimulation in a single treatment using ball sealers for diversion and CO2 for load recovery. A second method is to break up the large interval into smaller segments treating and isolating with plugs. The third technique employs packers and sleeves with CO2 for load recovery. The production results from these techniques are compared.
An Integrated Geological and Engineering Assessment of Fracture Flow Potential in a Middle-East Carbonate Reservoir
Authors: Whitaker A. E. , Kabir C. S. , Narr W. 
Published: December 2007

AbstractThe extent to which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined a Lower Cretaceous grainstone for which production extending over 50 years, including recent horizontal drilling, has provided some clues about fractures, but their exact locations, intensity and overall effect have been elusive. This study attempts to discern open fractures, if any, and their locations to facilitate building next generation earth and flow-simulation models.The geological assessment involved mapping fault orientations from seismic and analyzing image logs and cores for fractures. Fracture trends are in the NE and SW quadrants and fractures are mineralized toward the south and west of the field. Pressure falloff tests on some peripheral injectors indicate partially sealing faults. Most of these wells lie on seismic-scale faults mapped in the reservoir. Some wells show fractured-reservoir production characteristics and rate-transient analysis on a few producers indicates localized dual-porosity behavior. Producers proximal to dual-porosity wells display single-porosity behavior, attesting to the notion of localized fracture response. The spatially-restricted fracture signature may be owing to fracture or vug zones, or to low-permeability reservoir.Presence of fractures was discerned by constructing the so-called flow-capacity index (FCI), which is the ratio of khwell (welltest-derived value) to khmatrix (core-derived property). Data from 80 wells showed khmatrix to be consistently higher than khwell, with the p-50 reciprocal-FCI being 13, a relationship that suggests insignificant fracture production in these wells.
New Cleanup System for Gravel-Pack Completions: A Synergy of a Unique Acid System and Special Rotating Jetting Tool
Authors: Aguiar Jacqueline , PorDeus Jefferson M. , Almeida João B. , Melo Ricardo C. B. , Aboud Ricardo S. , Duque Luis 
Published: December 2007

Abstract
Gravel packs completions are widely used today on unconsolidated formations worldwide, as to provide sand control, and, as such, behaves as a filter. A filter is subjected to be plugged by fines, (heavy) hydrocarbons, scale depositions, among others, which may result in a considerable drop of production, or even total lack of.
The synergism of coiled tubing rotating, cyclical jetting tools, and adequate acid systems has demonstrated great results in Northeast of Brazil. The cyclical jetting tool acts to disaggregate plugging particles from the gravel, and the acid acts to chemically dissolve acid soluble plugging materials.
The acid system utilized is quite unique and simple. The method consists of pressure cyclically jet solvent and a small amount of a specially designed acid system, to clean up the gravel pack. No acidic flushes are used ahead or after the acid system, because the acid system is a high pH one (2 – 3), and uses an organophosphonic acid to control the dissolution of carbonates, and, therefore, controls the precipitation of insoluble fluorides. This way, release of calcium ions is less likely to occur. The main acid system is hydrofluoric (HF) based, generating HF on a controlled fashion, using much less hydrochloric acid (HCl) when compared to regular HF acid systems.
This paper describes three gravel packed wells treated with this single step acid system. These wells were very similar, and used the same acid recipe However, the first well was treated with a rotating pressure cycle jetting tool, and the remaining two wells used a different pulsation tool. All wells showed production increase, but the first well yielded much better results compared to the last two. Results from these three treatments will be presented and compared as towards the effectiveness of coiled tubing tools deployed.
Subsidence Due to Fluid Withdrawal in Fractured Reservoirs
Authors: Atashbari Vahid , Ahmadi Mohabbat 
Published: December 2007

Abstract
Land subsidances around the world and also several casing collapses in some fields of Iran, in drilling and producing time, and also in the period of no production, emphasis the rule of geomechanic factors, the overview of Geomechanical studies of fractured reservoirs.
It's clear to predict subsidence (rock compressibility) in sandstone rocks, and some of the professional experts have been worked on it, but about the fractured reservoirs, there are some differences. Regarding to the depth and size of fractured reservoir, in most cases there is no evidences in the surface related to compressibility of underground producing formation, that's why many of petroleum engineers neglect it, so they don't study it in the modeling and reservoir management while some of downhole assemblies problems are related to the pore pressure decrease, porosity loss and in some cases fault activation were caused by subsidence.
And we will show in this paper that Subsidence occurs in the Fractured reservoirs and beside the damages, petroleum experts can use it to increase recovery rate of oil and gas.
A Review on Microbial Enhanced Oil Recovery With Special Reference to Marginal/Uneconomical Reserves
Authors: Zahid S. , Khan H. A. , Zahoor M. K. 
Published: December 2007

Abstract
Oil and natural gas are vital for any economy and the importance of these resources in determining the social stability and economic viability of a nation is enormous. As the search for petroleum continues, recovery of known reserves must be improved if the goal of avoiding shortages is to be met. In today's energy sector, the high oil prices have driven the oil companies to recover the maximum amount of oil with the lowest production costs. Thus, economic production of oil and gas resources requires carefully engineered recovery projects of increasing technical complexity and sophistication.
One of the promising recovery methods is the microbiological enhanced oil recovery (MEOR). MEOR technology has the potential to be one of the reliable technologies that suits best the economic constraints of the current oil markets. The technology is a potential alternative to other EOR/ IOR methods, as it is being implementing in most parts of the world with satisfactory results not only form economics point of view but also from having lesser environmental impact.
The paper provides a review on MEOR technology and discusses it with special reference to marginal and/or uneconomical reserves. The goal of cost reduction, which is a major objective in any recovery methods, can be met by using MEOR technology which involves injecting a small amount of a solution containing microorganisms to spread through the reservoir and consequently produce desirable chemicals and gases that will enhance oil recovery and therefore profit. The paper also outlines the strategies to identify and meet the challenge of recovering large proportions of oil using MEOR techniques which could be very helpful in closing the energy gap by draining large proportions of oil which is left behind and minimizing the supply and demand difference in today's "energy hungry world".
Calculation of Flowing Optimum Bottomhole Pressure Constraint Based on Bubblepoint-Pressure-vs.-Depth Relationship
Authors: Obeida T. A. , Mosallam Y. H. , Al-Mehairi Y. S. 
Published: December 2007

Abstract
Thick reservoirs usually have variations of PVT properties such as bubble point pressure and dissolved gas oil ratio with depth. A considerable effort usually spent to describe such properties to be used in dynamic models either in Black Oil or compositional simulators. However, during predictions many dynamic models set the BHP constraint as a constant value for all producers in the entire reservoir regardless of perforations depth. Usually this constant value is close to the average bubble point pressure or a little higher to ensure single phase (oil) production and not considering changing of bubble point pressure with depth.
The above procedure introduces uncertainty regarding well potential, which involves a risk of not presenting accurate well performance in the simulator and would impact oil production and recovery forecasts.
The proposed method was developed to calculate following BHP constraint based on bubble point pressure versus depth relationship for each grid cell in the dynamic model, thus creating 4D-array (I, J, K, BHP constraint) for the entire reservoir.
The proposed method is fully automated and tested to assign BHP constrains in schedule section of huge dynamic model (2.6 million cells) with 600+ wells.
Two prediction cases were tested (each case run twice, one run with constant BHP constraint for all the produces and the other one using variable BHP constraint recommended by the proposed method) to evaluate the impact of BHP constraint on production and oil recovery forecasts.
The results of these two runs showed a considerable difference in length of oil production plateau and oil recovery forecast, but negligible differences in gas oil ratio.
The proposed method could be used for any dynamic model with vertical and/or horizontal variation of bubble point pressure to calculate an optimum BHP and thus WHP to maximize production rate without the risk of introducing gas phase at reservoir conditions.
The Effect of Positive Coupling and Negative Inertia on Deliverability of Gas Condensate Wells
Authors: Carvajal G. A. , Arreaza E. , González C. , Cesin C. , Fernández M. , Bello J. 
Published: December 2007

Abstract
Most of the cases in gas condensate wells produce below dew point pressure generating a saturated zone in liquid that blockage the gas flow efficiency to the well. Not only is the gas well productivity affected by fluid but also velocity. The conventional theory to analyze the phenomena associated at rate dependent is commonly interpreted using Isochronal or flow-after-flow tests. After this test, the negative impact of inertia on gas deliverability can be very well analyzed using special graphics. However, the actual effect related to capillary number and its dependency with velocity, called Positive coupling, is not yet analyzed in transient tests. As it has been mentioned in literature, the effect of coupling over gas condensate wells improves the pair of krg and krc and minimized the effect of skin rate dependent.
Flow-after-flow tests of 6DD+1BU have done in gas condensate wells in the Monagas Field, Venezuela. The results have shown that the wells in this field produce under the Non-Darcy flow regime and that its deliverability is decreasing due to condensing banking and the effect of inertia. Nevertheless, the flow-after-flow test revealed that, inertia is important at lower rate when a liquid saturation is significant but positive coupling becomes more important at higher rate. As a result, an increasing of condensate liquid rate and an optimization productivity point has been obtained.
This paper presents a methodology to analyze the Non-Darcy effect and to observe the competition between inertia and coupling. The most important contribution of this work is that gas well deliverability forecast can have a best estimation and a new developement plan can be proposed for a full field case. According to this test, the gas well productivity can be improved with the sense of recover more liquid of condensate.
Flow-Based Determination of Hydraulic Units
Authors: Schatz B. M. , Heinemann Z. E. 
Published: December 2007

AbstractIt is common knowledge that the identification of hydraulic units is vital for the construction of reservoir simulation models that preserve dynamically relevant geological features from the underlying geological model.To date, both static-based and flow-based techniques were suggested for assessing hydraulic units. The static-based methods are used more commonly and are based on the minimization of a statistical measure of permeability heterogeneity or on establishing a relationship between log and core derived reservoir properties. The dynamic methods are based on single phase numerical simulation.This paper presents a new flow-based method to determine hydraulic units considering multiphase flow, gravitational phase separation and capillary forces. The underlying concept assumes that, for every geological block, it is possible to estimate the time that is necessary for a fluid particle to traverse it laterally. The best way for that is a three dimensional streamline simulation. A stack of blocks can be lumped vertically to a hydraulic unit, if the time, which is necessary to achieve the vertical saturation equilibrium, is within a defined fraction of the traverse time. A multiphase simulation will be performed considering the reservoir as isolated columns. Water will be placed on top and then it will be calculated how far the vertical equilibrium can be achieved within 10 to 20 % of the local traverse time. The blocks, for which the required equilibrium is achieved, can be members of the same hydraulic unit. This method takes both the lateral flux and the vertical heterogeneity into consideration.The paper presents a full field example to demonstrate the applicability of the suggested method.
Past Technologies Emerge Due to Lightweight Proppant Technology: Case Histories Applied on Mature Fields
Authors: Aboud Ricardo S. , Melo Ricardo C. B. 
Published: December 2007

Abstract
In mature fields, operators are often seeking ways to increase the hydrocarbon recovery, with the help of reputable service companies. Well stimulation continues to be, by far, the preferred method of achieving such goal. Operators and service companies are continually screening out technologies which will deliver the highest benefit/cost ratio for a particular stimulation well treatment, maintaining focus on operational and health, safety and environment excellencies.
This paper addresses the rebirth of a past hydraulic fracturing technique, born in the 50's, and how it is being successfully applied on onshore mature fields in Brazil: batch fracturing. It is effective due to several technological advancements on proppant density, becoming lighter than conventional frac sand and yet with sufficient mechanical properties to withstand bottom-hole environments. Batch fracturing is now contributing to equally efficient, and more economical well stimulation treatments, providing good economical returns to operating companies.
Batch-Fracturing had limited success in the past. This was due to the available frac fluid and proppant technologies at that time. It is desirable that proppants have low settling when carried by a fracturing fluid, from the time they are added into such fluid, until the end of the pumping process. Batch fracturing applications are on the rise, due to the new families of ultra lightweight proppants, with specific gravities ranging from 1.05 to 1.75. In batch fracturing, the proppant is added to the carrier fluid prepared in standard oilfield mixing tanks, eliminating the need of specialized mixing equipment such as blenders. Less sophisticated equipment on location implies in lower operational and logistical costs. The carrier fluid ("frac fluid") does not need to yield high levels of viscosity, and, by consequence, does not have a high load of chemicals (gelling agents, cross-linkers, related breakers…). With batch fracs it is possible to perform common but effective types of fracturing treatments, such as "skin-by-pass" (a fracture that by-passes the damaged zone), and "partial mono layer’ fracturing, both exemplified in this paper, through case histories.
Experimental Investigation of Secondary and Tertiary Gas Injection in Fractured Carbonate Rock
Authors: Karimaie H. , Darvish G. R. , Lindeberg E. , Torsæter O. 
Published: December 2007

Abstract
The use of CO2 has received considerable interest as a method of EOR but a major drawback is its availability and increasing cost. Therefore, as the number of CO2 injection projects increase, an alternative must be considered to meet the economic considerations. For this reason attention has been directed to nitrogen injection which may be a good substitute for CO2. The purpose of the experiments described in this paper was to investigate the efficiency of oil recovery by CO2 and N2 in fractured carbonate rock. The combined effects of gravity drainage and component exchange between gas in fracture and oil in matrix on oil recovery in fractured reservoirs subjected to CO2 or nitrogen gas injection are experimentally studied. Laboratory experiments have been carried out on a low permeable outcrop chalk, as an analogue to a North Sea reservoir rock. This was surrounded by a fracture, established with a novel experimental set-up. The experiments aimed to investigate the potential of oil recovery by secondary and tertiary CO2 and nitrogen gas injection at high pressure high temperature condition. The matrix block was saturated using recombined binary mixture live oil (C1-C7), while the fracture was filled with a sealing material to obtain a homogeneous saturation. The sealing material was then removed by increasing the temperature which in turn creates the fracture surrounding the core. Gas was injected into the fracture at pressures above the bubble point of the oil. Oil recovery as a function of time was monitored during the experiments.
Results from secondary gas injection experiments indicate that CO2 injection at elevated pressure and temperature is more efficient than N2 injection.
Results from tertiary gas injection experiments also show that injection of CO2 could significantly recover the oil, even after waterflooding, compared to N2 injection.
Risk Analysis for Comparison of Development Plans—Application of Utility Theory and Value of Information in a Real Field
Authors: Salomão M. C. , Figueiredo F. P. 
Published: December 2007

AbstractAt the time of selecting the development plan of a petroleum field, little information is available and the range of uncertainty is large. Once the main variables that most strongly affect the production behavior have been identified, the next step consists in generating the set of possible results for production forecast, and obtaining the probability distribution of the economical parameters, as the net present value (NPV). Depending on the range and nature of the uncertainty variables, the best way to protect the project, instead of collecting information, may consist in changing the exploitations strategy, in order to reduce reservoir risks. In next phase of exploitation of Marlim Sul field, Campos Basin, Brazil, the main source of uncertainty is an extensive fault, located in the middle of the reservoir, which breaks the oil zone into two blocks. According to the strategy of the original plan, the injection wells are located on one side of the fault, while the production wells on the other side. The sealing capability of this fault is a critical issue, since it could be an obstacle to oil sweeping by the water injection. To face this issue, we have two alternatives: either collect more information in order to reduce the level of uncertainty, or select an alternate plan, less sensible to transmissibility of that fault, and more adequate to the various scenarios. To compare these alternatives, we utilize uncertainty analyses, enriched with risk aversion considerations. The use of the expected monetary value (EMV) as parameter of comparison proved to be a good way to meet better all the scenarios, but not sufficient to traduce the economic risk of the project. The use of concepts of the utility theory indicated that the alternate plan has lower sensibility to critical uncertainty, is more protected against reservoir risks, and is the best development strategy to be implemented.
A Rigorous Stochastic Coupling of Reliability and Reservoir Performance When Defining the Value of Intelligent Wells
Authors: Aggrey G. H. , Davies D. R. 
Published: December 2007

Abstract
Long term equipment reliability frequently controls the Value created by Intelligent Well Technology. One of the barriers to intelligent well deployment is the inability to properly quantify Value terms of the loss of the intelligent system's ability to function properly to achieve the required reservoir or well management objectives. Recent publicised deterministic value calculation of intelligent wells does not permit proper decision making as this workflow frequently underestimates the potential value. In this paper we show a general methodology where a full stochastic reservoir reserve evaluation is coupled to a stochastic (Monte Carlo) reliability analysis of the I-well performance. This value creation is defined on the basis of a realistic mission reliability profiles for a conventional and an intelligent well.
The detailed methodology has been tested by modelling the production from a conventional and intelligent completion deployed in a typical North Sea fluvial type reservoir.
This new approach to value determination provides the information that forms the basis of a cost-effective, completion design.
Using Drillstem and Production Tests To Model Reservoir Relative Permeabilities
Authors: Matthews John D. , Carter Jonathan N. , Zimmerman Robert W. 
Published: December 2007

Abstract
There are many examples of dry oil production from portions of reservoirs where the local water saturation is high. When relative permeability data are available, predictions of the expected water cut are not zero, but typically 30-60%. This lack of agreement means that reservoir management using simulation models is questionable because such models can only mimic the observed reservoir production using data that bear little resemblance to measurements.
The first focus of this paper is to examine the uncertainties in the data that are used for the predictions. This then provides a numerically structured approach to adjustments that need to be made to data so that history matching of simulation models can be achieved. The relative permeabilities, rather than saturations and fluid properties, are shown to be the least certain of the relevant data.
The second focus is to explore the reasons why the relative permeability data are so uncertain. The evidence points to the fact that oil emplacement and subsequent geological history of the reservoirs have not been considered sufficiently in preparing core samples and making measurements. Greater reliance on drill-stem and early production tests is therefore crucial for deriving reservoir relative permeabilities until laboratories are able to mimic, within rock samples, oil emplacement as experienced in the reservoir.
The main source of data is from the abandoned UK North Sea reservoir (Maureen, block 16/29a).