bluuebunny/crossref_metadata_2025_split huggingface dataset:
Controlling Corrosive Biofilms by the Application of Biocides
Authors: Maxwell S. 
Published: December 2007

Abstract
Reports of corrosion failures implicating bacterial activity – and in particular the activity of Sulphate-reducing Bacteria (SRB) – continue to appear in the literature and documented case histories. In many cases, the Microbially Influenced Corrosion (MIC) has occurred despite the application of biocide chemicals into the affected system. It is not uncommon to hear of ‘ineffective biocides’, the implication being that the efficacy of the chemical to kill bacteria is questionable. It is clear, however, that the most commonly applied generic formulations of oilfield biocides (such as Glutaraldehyde, THPS, etc.) are effective killers of bacteria. If the field application of these chemicals does not result in acceptable microbiological control then the inference should be, not that the chemical is an ineffective biocide, but that the application of the chemical is such that it is not contacting the target bacteria with sufficient concentration, retention time and/or frequency to achieve a kill.
This paper presents an overview of how oilfield biocides can be applied such that those bacteria with a role in corrosion are controlled to sufficiently low levels to inhibit MIC. The emphasis is on seawater injection systems, where the majority of the total tonnage of oilfield biocide is applied. However, the key parameters are also relevant to oil production systems.
Formation Testing While Drilling - Conventional and Novel Applications
Authors: Buysch A. , Meister M. , Pragt J. , Freitag H.-C. , Hahne U. 
Published: December 2007

Abstract
With the introduction of a new LWD tool, it has now become possible to acquire formation pressure and mobility data during short breaks in the drilling process. Formation pore pressure and near wellbore mobility are key parameters for reservoir description. Traditionally, these data have been acquired with wireline formation testers, upon reaching section or well TD. In high angle wells, this is a time-consuming operation, as the tools have to be conveyed by drill-pipe. Providing this type of formation evaluation data with an LWD tool allows for a continuous approach to data evaluation and decision making and represents a significant opportunity for safe and cost-efficient wellbore construction.
The paper will briefly review the design and operation of a new formation pressure while drilling tool which is capable of performing optimized repeat pressure tests in less than one minute. The paper will use case histories from different operating areas to demonstrate the applicability of this formation tester to conventional applications, such as the determination of formation pressure, fluid contacts, reservoir connectivity, and near-wellbore mobility; and novel real-time applications, such as mud weight management, safe selection of casing point, calibration of pore pressure predictions, selection of wireline sampling points, reservoir monitoring, geo-steering, and obtaining data in high risk wells.
Improved Iterative Coupling of Geomechanics With Reservoir Simulation
Authors: Tran D. , Nghiem L. , Buchanan L. 
Published: December 2007

Abstract
The use of reservoir simulation coupled with geomechanics to model physical phenomena such as compaction, subsidence or shear failure etc. has been increasing. Different methods of coupling have been investigated by numerous researchers: fully implicit coupling, iterative coupling and explicit coupling. So far, the iterative coupling method appears to be the most preferable method for field-scale simulation. In this method, the porosity can be expressed as a function of pressure, temperature and mean stress. Since the parameters of the porosity function are evaluated in the geomechanics module, they are lagged and are kept unchanged (explicit formulation) during the solution of the reservoir flow equations. Therefore, the solution is computed less accurately than expected.
In this paper, a modification of the porosity formula for the iterative coupled method is described. The improvement includes the use of additional derivatives for the parameters to give a more implicit formulation of porosity with respect to pressure and temperature. In the modified porosity formula, the second order terms of compressibility are included. This modification makes the coupling implicit and gives a more accurate solution.
Some test cases will be performed to demonstrate how the modified porosity formula yields better solutions than the unmodified one.
Validation of Scale Prediction Algorithms at Oilfield Conditions
Authors: Kan A. T. , Wu X. , Fu G. , Tomson M. B. 
Published: December 2007

Abstract
Scale and corrosion continue to be serious and costly problems in oil and gas production facilities. Production engineers rely upon computer programs to predict the severity and location of scale deposition and corrosion. The core of these computer programs are algorithms to correlate a set of theoretically derived equations, e.g. the conditional solubility products in Oddo-Tomson saturation index and activity effect corrections in Pitzer theory of specific ion interactions, to a limited set of thermodynamic solubility data. Typically, the solubility data at various temperature and pressure are only available in low salinity matrix. The solubility in high salinity matrix is often done at STP with only simple background electrolytes, e.g. KCl. Limited mixed salt data are available and mostly consisted of seawater matrix at STP. Solubility data are more rigorously tested for halite and calcite, while they are scarce for other oil-field minerals, e.g. barite, gypsum, celestite, and metal-sulfides. Hence, the validity of these equations to extreme oil field conditions is not known. In this paper, a new corrosion-proof, high-temperature, high-pressure flow-through apparatus was developed to measure mineral salt solubilities under relevant oil and gas production conditions, i.e., high temperature, pressure, TDS (total dissolve solids), mixed ion matrices of sulfate, acetate, calcium, magnesium, and the presence of methanol and ethylene glycol. New solubility data illustrates the validity and limitation of the Pitzer activity correction of mineral salt solubilities. Pitzer equations have been shown to accurately predict scaling indices to within 0.1 SI, with ScaleSoftPitzer™, at extreme oil and gas production condition.
Improved Permeability Estimation through Use of Fuzzy Logic in a Carbonate Reservoir from Southwest Iran
Authors: Taghavi A. A. 
Published: December 2007

Abstract
The aim of this study is to predict permeability from well log data for a heterogeneous carbonate reservoir in the upper part of the Sarvak Formation (mid-Cenomanian to early Turonian) in an Iranian oil field. The permeability is a crucial parameter for reservoir modeling which is difficult to measure directly. Direct measurements of permeability are obtained form core plugs, if available. Continuous permeability values, however, need to be predcited indirectly from independent data. Three different methods have been tested for estimating the permeability: 1) permeability from effective porosity 2) multilinear regression, and 3) fuzzy logic. The two latter methods utilize raw well logs (gamma ray, density, neutron and sonic) to predict permeability. Core plug measurements have been used to validate the predictions.
Results from the study show that fuzzy logic yields better results than the two other methods. The multilinear regression is unable to represent the dynamic range measured on the core plugs (overestimated in low values and underestimated in high value). The permeability predicted from the effective porosity model is more or less similar to multilinear regression model, but relatively narrower. This is however to be expected as these models both indicates narrower ranges than fuzzy logic, because they are trying to fit with average values.
Foams for Controlling Water Production
Authors: Bhide V. , Hirasaki G. , Miller C. , Puerto M. , Robb I. , Norman L. 
Published: December 2007

Abstract
There is a great interest in the oil production industry in relative permeability modifiers (RPM) that can preferentially reduce water production without significantly affecting oil production. Various hydrophilic polymers have been studied for their RPM properties. This paper shows the potential of foam as RPM. Foams stable for a long time in presence of flowing water were developed using polymeric surfactants. Scale-up calculations show foam lifetimes long enough in field geometries for the process to be practicable. Foam tolerance to residual oil in water producing zones was produced by adding anionic surfactant to a nonionic polymeric surfactant. Resistance to flowing oil was, however, found to be unexpectedly high due to stable emulsion generation in porous medium. A process modification is shown to reduce the severity of this problem.
Creative Utilization for Oracle Database to Meet Petroleum Engineering's Needs
Authors: Shideed M. A. 
Published: December 2007

Abstract
This paper is a culmination of the database philosophy, concepts, structure, strategy and services provided to the engineers, geologists and management at Saudi Aramco. It introduces recent ideas and 25-years of experience in maintaining and safeguarding massive amount of data gathered from super giant onshore and offshore oil and gas fields.
It also shows how Aramco pioneers apply their own creative solutions for best utilization of the corporate database to support decision making, increase productivity and save costs. Two main areas will be highlighted; the data validation and user assistance techniques.
Production Data and Uncertainty Quantification: A Real Case Study
Authors: Nicotra G. , Godi A. , Cominelli A. , Christie M. 
Published: December 2007

Abstract
It is becoming increasingly important to quantify uncertainty in reservoir performance. History matching is carried out to improve field knowledge and simulation reliability by ensuring that simulations match observed production. In real field cases at most a few reservoir scenarios are used to estimate production performance uncertainty and this leads to a lack of reliability of the uncertain forecasts.
The Neighbourhood Algorithm (NA), originally developed for earthquake seismology, provides a framework for generating history matched models and assessing uncertainty in production forecasting. It is a stochastic approach approximating the structure of the likelihood function by Voronoi tessellation and using all information previously obtained about the model space.
In this paper the first application of NA on a real oil reservoir is described. The case is the Rigel field, an under-saturated black-oil model producing since July 2001 with 6 producers and 2 water injection wells. The history-matched production data are static and flowing bottom-hole pressures and water cut.
A previous manual history match had obtained good response at field level and acceptable responses at well by well level.
We applied NA, using the same approach (varying fault transmissibilities) that had been used in the manual history match. We generated 640 Eclipse models that spanned the parameter space and obtained 396 matches that were better than those with the traditional history match. Those results have been achieved in a significant reduction of time.
To correctly quantify the uncertainty in reservoir forecast, we have to obtain the posterior probability of each model - that is the probability of the model given the history data. This is accomplished with a separate code (NAB) running Markov Chain Monte Carlo.
This paper will describe how we obtained the history match, the formulation and choice of misfit definition which is critical to obtain accurate predictions of uncertainty ranges and the use of NAB code to uncertainty estimation.
Interpretation of Skin Effect from Pressure Transient Tests in Horizontal Wells
Authors: Al-Otaibi A. M. , Ozkan E. 
Published: December 2007

Abstract
Most horizontal wells have non-uniform distribution of skin along their lengths and this creates a challenging problem in the interpretation of their pressure-transient responses. The theory indicates that the rigorous incorporation of non-uniform skin distribution into horizontal well pressure-transient models requires the knowledge of not only the skin distribution but also the flow rate distribution into the horizontal well from the reservoir. Because this information is not normally available to the analyst, standard pressure interpretation techniques and tools assume uniform distribution of skin with the expectation that the estimates would correspond to some average of the skin distribution. The question that has not been adequately addressed in the literature is the physical meaning of the skin estimates from different pressure-transient analysis tools in common use. Because this question has not been adequately addressed, purely geometrical interpretations of the skin estimates have been proposed to calculate horizontal well productivities and develop flow models.
In this paper, we generate synthetic pressure-transient responses for different non-uniform skin distributions along a horizontal well and analyze these responses by using the conventional tools that assume uniform distribution of skin. Skin estimates from well-test interpretation are then compared with the known skin distributions.
The findings of this study are practical and important. First, the pressure drop caused by skin depends on the flow regimes if the skin distribution is non-uniform. Because the models used in commercial software assume the same additional pressure drop due to skin, the regression analysis can only match one of the flow periods for a constant skin value. To interpret the meaning of this skin estimate, we used the semi-log analysis techniques and demonstrated what type of average the estimated skin represents for different flow regimes and different skin distributions. For most cases, the estimates of skin from early-time radial flow analysis represent the arithmetic average of the skin distribution which may be useful for stimulation decisions. The skin estimate from the pseudo-radial flow period corresponds to the skin pressure drop at the heel of the horizontal well, which represents the additional pressure drop to be considered in the productivity calculations. We demonstrate that the geometric interpretation of the non-uniform skin effect proposed in the literature is inaccurate and leads to significant errors in the calculation of horizontal well productivity.
Quantifying Uncertainty for the PUNQ-S3 Problem in a Bayesian Setting With RML and EnKF
Authors: Gao G. , Zafari M. , Reynolds A. C. 
Published: December 2007

Abstract
The well known PUNQ-S3 reservoir model represents a synthetic problem which was formulated to test the ability of various methods and research groups to quantify the uncertainty in the prediction of cumulative oil production. Previous results reported on this project suggest that the randomized maximum likelihood (RML) method gives a biased characterization of the uncertainty. A major objective of this paper is to show that this is incorrect. With a correct implementation of the RML method within a Bayesian framework, we show that RML does an adequate job of sampling the a posteriori distribution for the PUNQ problem. In particular, the true predicted oil production lies within the band of predictions generated with the RML method and is not biased.
Very recently, the Ensemble Kalman Filter has gained notoriety, because it is very easy to couple with any reservoir simulator, allows one to continuously assimilate dynamic data as the forward simulation run is done and allows one to characterize uncertainty in performance predictions. When applied to the PUNQ data set, we show that this method also gives a reasonable quantification of the uncertainty in performance predictions with an uncertainty range similar to the one obtained with RML.
On-Site Iron-in-Brine Removal: A Technological Advance
Authors: Javora P. H. , Qu Q. , Berry S. 
Published: December 2007

Proposal
Excessive amounts of soluble iron in a work-over and completion brine contributes to the formation of external and internal filter cakes, increases damage to the formation, contributes to the corrosion process, and is detrimental to the completion process. Therefore, the removal of iron from high-density zinc-based brines is critical.
Conventional treatments often utilize processes which include many hours of reaction time, addition of strong acids, multiple filtration steps, significant amounts of chemical neutralizers, absorption of contaminants on finely-divided activated carbon, addition of substantial amounts of dry calcium chloride salt, and even the use of strong oxidizing agents, etc. For each used brine, a representative sample must be tested in the laboratory before a proper iron removal process can be identified and documented for a forthcoming implementation, which is usually performed at the supplier's plant.Current processes are not only costly, but also impossible to carry out during ongoing completion operations.
New chemistry has been developed and implemented that effectively and efficiently removes iron from high-density zinc-based brines without complication. This chemistry represents an important technological advance that allows used zinc-based brines to be reclaimed in a single, uncomplicated, no-fuss process. When followed by simple DE filtration, the typical residual-iron content of the reclaimed zinc-based brine will be less than 20 ppm. This paper presents the chemistry of iron and its removal, introduces the new iron-removal chemistry, presents and summarizes laboratory and field data, and discusses the applications and benefits for the supplier and customer.
Applicability of Enhanced Oil Recovery Techniques on Mature Fields—Interest of Gas Injection
Authors: Hunedi S. , Danquigny J. , Morel D. , Maubeuge F. , Guarrino A. 
Published: December 2007

Abstract
Enhanced Oil Recovery (EOR) techniques are a clear illustration of the increasing challenges faced by the oil industry to extend lifetime of their developed fields and accordingly increase their ultimate reserves.
DEZPC wants here to share its experience in EOR techniques by presenting the results of the exhaustive screening performed on its entire portfolio. The initial screening aimed at quantifying the applicability of gas injection (nitrogen, CO2, flue gas, hydrocarbon gas, and water-alternate-gas injection), air and steam injection, in-situ combustion and chemical methods (including polymer flooding and microbial recovery) for highly mature fields in clastic environments.
On a second phase, the field candidates selected out of the screening were further studied in order to quantify the interest of EOR in terms of increase of both production and reserves. Two major fields of DEZPC actually presented many characteristics that hint a potential interest of gas injection. Extensive reservoir simulation work was therefore performed in order to rank the injection processes (lean gas, rich gas, miscibility) and to assess their economy.
Objectives of gas injection are to take advantage of gravity drainage in order to minimize residual oil saturation by providing adequate pressure support. Results, which have evidenced complex dynamic behavior on both fields, are discussed, mainly in terms of planning (more specifically how to benefit of simultaneous water and gas injection, when water injection has to be stopped in order to optimize the gas gravity drainage).
More generally, such modeling works on mature fields have enabled to stress that an optimum knowledge of the dynamic field behavior is mandatory to assess investments and risks associated to such complementary development.
Stability of High Molecular Weight Hydrocarbons in a Carbonate Reservoir
Authors: Broad T. J. , AI Binbrek M. , Neilson D. , Gibson Adrian P. 
Published: December 2007

Abstract
An extensive review of PVT data has been performed on a large carbonate reservoir in an onshore Abu Dhabi field with over forty years of production history. The lateral and vertical distribution of initial fluid compositions in this reservoir is very complex. The objective was to map the initial fluid composition and develop a single EOS to model the fluid properties throughout the reservoir.
This paper describes the review of the EOR and SDS (Solid Deposition Studies) laboratory studies and the impact of the precipitation of high molecular weight hydrocarbons (HMWH) on the fluid properties and the tuning of the EOS. The EOR and SDS studies dated back to the early nineties; the earliest studies did not include vital data on the deposition of HMWH. The latest SDS clearly indicate that the reservoir fluid was initially unstable with respect to solid deposition and that this condition can be aggravated by gas injection, (except when the gas is predominantly H2S).
Industry standard PVT software was used for the simulation of the HMWH precipitation, but careful modifications of the fluid composition and properties were required in order for the EOS to match the laboratory studies.
This paper addresses some of the issues related to the phenomenon of HMWH precipitation and illustrates the reliability of EOS simulations to predict this behaviour. In addition, various recommendations are made for enhancing laboratory analytical programs so that more pertinent data can be acquired.
Surface Tension of Completion Brines
Authors: Nasr-El-Din H. A. , Al-Otaibi M. B. , Al-Aamri A. M. , Ginest N. 
Published: December 2007

Abstract
Various brines are used in completion operations. These brines consist of a salt of mono or divalent cation (Na, K, NH4, or Cs) and a certain anion (Cl, Br, or HCOO-). Mixtures of these salts are also used under certain conditions. The surface tension of these brines plays a key role in determining the productivity of gas wells. A low surface tension is required to reduce the capillary forces that trap the aqueous phase in the formation. Accumulation of the aqueous phase near the wellbore area, known as water blockage, leads to a reduction in the relative permeability to gas, which can in turn, significantly reduce well productivity.
This work provides for the first time the surface tension of completion fluids at temperatures up to 150°C, and densities up to 93 pcf. A pendant drop apparatus specially designed for corrosive fluids was used to measure the surface tension between various completion fluids and nitrogen gas.
The effects of commonly used additives on the surface tension of completion fluids were also studied in detail. These additives included: xanthan gum, fluid loss control additives, citric acid, methanol, buffering agents, and surfactants.
In addition to surface tension values of solids-free completion fluids at temperatures up to 150°C, experimental results indicated that several additives are capable of significantly lowering the surface tension of completion fluids. The results obtained in this study can be used to better design completion fluids that are utilized in deep gas wells.