bluuebunny/crossref_metadata_2025 huggingface dataset:
A Combination Technology of Profile Control and Mini-type Surfactant Flooding: Laboratory Evaluation and Field Application
Authors: Zhao Huating , Yang Huanwen , Wu Xuguang , Zhao Puchun , Xiao Liping
Published: December 2007

Wenmingzai (WMZ) is a mature water-flooded Oilfield, which is characterized by high temperature (80°F), high salinity (8°104mg/L) and high heterogeneity. After long time of waterflooding, the heterogeneity is getting worse and worse. Many injection wells were treated by injecting water-plugging agents, but the treatment results are fading with treatment times. To improve treatment results, a combination technology of profile control and mini-type surfactant flooding has been applied since 1998. This paper has introduced the laboratory experiment evaluation and field application results of the combination technology. Based on the salinity, hardness and temperature of this oilfield, a new non-ion surfactant has been developed. Effects of temperature, surfactant concentration, salinity and formation water hardness on surface tension between the surfactant and reservoir oil have been studied. Results show the tension has a magnitude of 10−3 mN/N at 65° and 10−2 mN/N at 80° under reservoir brine conditions, and it can resist 5°104mg/L of brine and 1500mg/L of Ca2+ and Mg2+. Adsorption of the surfactant onto reservoir cores has been studied by static and dynamic experiments. Results show that the dynamic adsorption density is less than 0.5g/g. Core flooding experiments were carried out to prove that the surfactant could improve recovery by more than 10%. Two application examples were analyzed to show how to choose candidate wells and how to operate the injection procedures. This combination technology can be widely used to improve oil recovery for mature oilfields.
Real-Time Reservoir Model Updating Using Ensemble Kalman Filter
Authors: Wen X. -H. , Chen W. H.
Published: December 2007

Ensemble Kalman Filter (EnKF) has been reported to be very efficient for real-time updating of reservoir model to match the most current production data. Using EnKF, an ensemble of reservoir models assimilating the most current observations of production data are always available. Thus the estimations of reservoir model parameters, and their associated uncertainty, as well as the forecasts are always up-to-date.

In this paper, we apply the EnKF for continuously updating an ensemble of permeability models to match real-time multiphase production data. We improve the previously EnKF by resolving the flow equations after Kalman filter updating so that the updated static and dynamic parameters are always consistent. By doing so, we show that the production data are also better matched for some cases. We investigate the sensitivity of using different number of realizations in the EnKF. Our results show that a relatively large number of realizations are needed to obtain stable results, particularly for the reliable assessment of uncertainty. The sensitivity of using different covariance functions is also investigated.

The efficiency and robustness of EnKF is clearly demonstrated using an example. By assimilating more production data, new features of heterogeneity in reservoir model can be revealed with reduced uncertainty, resulting in more accurate predictions.
The Relative Effects of Acid Number and Temperature on Chalk Wettability
Authors: Zhang P. , Austad T.
Published: December 2007

Contrary to sandstone reservoirs, 90% of carbonate oil reservoirs are characterized as neutral to preferential oil-wet. It is documented that the water wetting nature increases as the temperature increases, which is opposite to the behavior of sandstone reservoirs. The content of carboxylic acid groups in the crude oil, i.e. the acid number, AN, appeared to be a crucial wetting parameter, which very often dictates the wetting nature of the reservoir: the water wetness decreases as the AN increases. It is, however, well known from organic geochemistry that the AN of a crude oil is linked to the reservoir temperature because decarboxylation takes place as the temperature increases. Therefore, the temperature and the AN are not independent wetting parameters for carbonates. In the present experimental investigation, we have decoupled the connection between temperature and AN and studied the individual effects of these two wetting parameters towards chalk. The porous media used are outcrop chalk from Stevns Klint with a very high porosity, about 45-50%, and low permeability, about 2 mD. A number of tests were performed using oils with different AN (0.17-2.07 mgKOH/g). The cores, which contained initial brine saturation of about 25-39%, were aged for 30 days in the corresponding crude oils at different temperatures (40, 80 and 120 C). A recently developed new wettability test method was used to quantify the wetting index. This is a very important technique, because the well known Amott test is not very sensitive close to neutral conditions. The conclusion from the work was that the AN was the most important wetting parameter, and the aging temperature only played a very minor role in determining the wetting conditions. Also a correlation between the new wetting index and Amott water index was established.
Seawater as IOR Fluid in Fractured Chalk
Authors: Austad T. , Strand S. , Høgnesen E. J. , Zhang P.
Published: December 2007

The wetting nature of a carbonate reservoir determines the potential of improved oil recovery by water injection, especially if the formation is highly fractured, which often is the case for chalk formations. The initial wetting state is mostly governed by the properties of the crude oil, where the acid number, AN, appeared to be a crucial parameter. The reservoir temperature plays, however, a minor role as a wetting parameter. Improved oil recovery by water injection decreases as the water-wetness decreases due to decrease in spontaneous imbibition. The relative high specific surface area of chalk, about 2-3 m2/g, indicates that compositional properties of injected fluid could influence the wetting properties of the formation somewhat during the production phase. The exceptional good response of seawater injection into the Ekofisk formation is an indication of a special rockwater interaction, which improves the spontaneous displacement of oil. In the present paper, we will summarize the results from ongoing research to improve spontaneous imbibition of water into oil-containing chalk samples at various wetting states and temperatures. The chemical composition of the imbibing fluid is discussed in relation to the composition of initial brine and changes in the rock-fluid (water and oil) equilibrium conditions. Major observations are: (1) The presence of sulfate in seawater improved spontaneous imbibition at all wetting conditions tested. (2) Sulfate is a potential determinig ion towards chalk, which has impact on the wetting state in a positive way. (3) The adsorption of sulfate onto chalk increases as the temperature increases, which implies that the efficiency of sulfate as an active wettability modifier is improved as the temperature increases. (4) The relative increase in sulfate adsorption onto chalk increases at temperatures above 100°C. (5) Injection of produced water with a high Ca2+/SO4 2- ratio is recommended to be used only as pressure support and not as an oil displacing fluid.
Effects of Organism Size and Weight on the Synthetic-Based Mud Sediment Toxicity Bioassay Using Leptocheirus Plumulosus
Authors: MacGregor R.
Published: December 2007

Proposal

The key objective of this study was to identify controllable test parameters that might reduce test variability for the 4-day sediment toxicity bioassay of synthetic-based drilling muds (SBM) required for offshore drill cuttings discharge into the Gulf of Mexico. The factors that produce an effect on the performance of the SBM-sediment toxicity bioassays include quality of mixing procedures, sediment composition, test organism health, size and weight. This study was designed to determine how different sieve sizes might affect the size and weight variability of selected Leptocheirus plumulosus and how this selection affected the LC50 test results of the SBMsediment bioassays. The design focused on organisms collected after passing through a 1000-micron sieve and retained on either 850-micron or 710-micron sieves. Weights of sieve-selected organisms were measured before each bioassay. The data from these bioassays was used to illustrate the relationships between organism sieve size, organism weight, variability of weights within sieve size, LC50 responses to SBMs and the variability of LC50 responses. These test parameters were evaluated for their degree of effect on the SBM-sediment toxicity bioassay test result variability.
Atomic Force Microscopy Study of Wettability Alteration
Authors: Kumar K. , Dao E. K. , Mohanty K. K.
Published: December 2007

Waterflooding recovers little oil from fractured carbonate reservoirs, if they are oil-wet or mixed-wet. Surfactant-aided gravity drainage has the potential to achieve significant oil recovery by wettability alteration and interfacial tension (IFT) reduction. The goal of this work is to investigate the mechanisms of wettability alteration by crude oil components and surfactants. Contact angles are measured on mineral plates treated with crude oils, crude oil components, and surfactants. Mineral surfaces are also studied by atomic force microscopy (AFM). Surfactant solution imbibition into parallel plates filled with a crude oil is investigated. Wettability of the plates is studied before and after imbibition. Results show that wettability is controlled by the adsorption of asphaltenes. Anionic surfactants can remove these adsorbed components from the mineral surface and induce preferential water wettability. Anionic surfactants studied can imbibe water into initially oil-wet parallel plate assemblies faster than the cationic surfactant studied.
The Discovery of High-Molecular-Weight Naphthenic Acids (ARN Acid) Responsible for Calcium Naphthenate Deposits
Authors: Baugh T. D. , Grande K. V. , Mediaas H. , Vinstad J. E. , Wolf N. O.
Published: December 2007

Calcium naphthenate deposition is among the most challenging obstacles to high production regularity for oilfields where acidic crude oils are produced. Until now it has generally been acknowledged that the deposit is made up of calcium soaps of the naphthenic acids in the crude oil, though with a slight overrepresentation of the lighter acids. In this paper, however, we demonstrate that this is not the case. Through a combination of several analytical techniques – the most important being Potentiometric Titration, LC/MS, NMR, and VPO – the ARN acid has been identified as the dominating constituent of these deposits. The ARN acid is a family of 4-protic carboxylic acids containing 4 - 8 unsaturated sites (rings) in the hydrocarbon skeleton with mole weights in the range 1227 – 1235 g/mol. The mole weight of the homologous ARN acids series are 1227, 1229, 1231, 1233, 1235 (basic structures) + n×14 (n = number of additional CH2-groups in hydrocarbon skeleton). The ARN acid with mole weight 1231 has C80H142O8 as empirical formula.

The present paper describes the different analytical methods leading to the ARN acid discovery. Furthermore it discusses possible ARN structures and methods for quantitative ARN detection in crude oils. The ARN acid has proved to be the main component in naphthenate deposit from oilfields offshore Norway, Great Britain, China and West Africa. The implications of the discovery to current calcium naphthenate treating strategies will be briefly discussed.
Experimental Study on Asphaltene-Induced Formation Damage
Authors: Nabzar L. , Aguilera M. E. , Rajoub Y.
Published: December 2007

Application of many EOR technologies provokes productivity decline due to asphaltene deposition leading to wellbore plugging and flow restriction in tubing, flow lines and production facilities. The present study aims at investigating the kinetics of asphaltene deposition using both model system and actual crude oil. Experiments were performed by injecting asphaltenic fluids into capillaries and outcrop sandstones. The effect of flow rate, presence of resins and asphaltene aggregation were investigated.

It was experimentally evidenced that asphaltene deposition is a continuous process that results in multilayer deposition. It was demonstrated that asphaltene deposition takes place according to the well-known scaling law of Diffusion Limited Deposition (DLD) regime. The results demonstrated that multilayer deposition might be hindered by shear rate. It was shown that, above a first critical shear rate (lower critical shear rate) that depends on asphaltene aggregation state, the multilayer deposition kinetic is slowed down upon increasing injection flow rate. The flow rate dependence switches from−2/3 to −5/3 power law. This latter exponent is thought to encompass the classical −2/3 dependence of the DLD regime and the effect of asphaltene detachment that, therefore, varies as the flow rate to the power −1. The results put into evidence the existence of an upper critical shear rate value beyond which multilayer deposition is totally hindered. The value of this critical shear rate depends on resin content and varies exponentially with solvent quality.

In conclusion, the experimental results showed that the "colloidal approach" is a valuable route for asphaltene deposition modeling that can be used to develop a more realistic asphaltene near-wellbore damage model that takes into account the actual physics of the process.
New Technique for Evaluating Antiagglomerate Gas-Hydrate Inhibitors in Oilfield Applications
Authors: Oskarsson H. , Lund A. , Hjarbo K. W. , Uneback I. , Navarrete R. C. , Hellsten M.
Published: December 2007

Gas hydrate inhibitors have been evaluated using different techniques in the past.In particular, anti-agglomerates have been evaluated in Rocking Cells, Stirred Autoclaves, different types of pipe flow devices such as the rotating wheel device, and regular pipe rheology.In this paper the development of new anti-agglomerate chemistry is illustrated using a new technique where miniature autoclaves, that allow for the simultaneous testing of up to 47 samples in an affordable way, are used.Temperature and turbidity are measured directly, whereas the viscosity of the mixture is indirectly measured via a unique rotating stirring device.
Theoretical Modeling of Tertiary Structure of Paraffin Inhibitors
Authors: Lindeman O. E. , Allenson S. J.
Published: December 2007

Theoretical molecular-mechanical modeling of conventional paraffin inhibitors was performed to determine a correlation between the tertiary structure of paraffin inhibitor polymers and their melting and glass transition temperatures, crystallinity, viscosity, and performance. The results allowed implementation of targeted syntheses of new advanced paraffin inhibitors. The physical properties and performance of these new paraffin inhibitors were successfully predicted by the molecular-mechanical modeling.
Salinity, pH, and Surfactant Concentration Effects on CO2-Foam
Authors: Liu Yi , Grigg Reid B. , Bai Baojun
Published: December 2007

The influence of a number of parameters on CO2-foam stability and surfactant adsorption at reservoir conditions are determined. In this work changes of pH from 1 to 12, salinity from 0 to 25 wt%, and surfactant concentration from 0 to 1 wt % were tested for foam stability in a bubble chamber and for adsorption in a static adsorption apparatus using pure kaolinite powder. The mechanisms by which pH and salinity influence CO2-foam behavior are also discussed in the paper.

Stability of CO2-foam is surfactant concentration-dependent. The foam was stable under all tested pH and salinities at concentrations both below and above the critical micelle concentration (CMC) except at the lowest concentration tested (0.005 wt%). The adsorption of surfactant onto kaolinite increased with salinity for both NaCl and CaCl2 with the divalent salt system inducing a higher adsorption onto the kaolinite.
General Stability Criteria for Compositional and Black-Oil Models
Authors: Wan J. , Sarma P. , Usadi A. K. , Beckner B. L.
Published: December 2007

Proposal

A numerical scheme is unstable when the result, during the solution procedure, becomes unbounded. Explicit schemes, such as IMPES, are limited by stability conditions. Robust stability criteria can help in understanding the numerical scheme's behavior and can also be used as switching criteria for adaptive implicit models. In this paper, general stability criteria are derived for black-oil and compositional models with various levels of implicitness, including pressure implicit, pressure and saturation implicit and fully implicit.

Unlike the existing stability analyses for reservoir simulation models, we start with the most general multiphase multicomponent model framework and derive stability criteria using Fourier stability analysis on the equations to which explicit schemes are applied. Our approach takes into account all of the major mechanisms governing fluid flow, i.e., convection, diffusion, capillary forces, gravity, fluid and rock compressibility, vapor-liquid equilibrium in compositional models and solubility in black-oil models. The derived criteria can provide a reasonable measure in the most general models. Black-oil models are treated as special cases of compositional models.

Our approach is compared to existing approaches; its application within ExxonMobil's reservoir simulator, EMpower, is discussed.
Sorption of Surfactant Used in CO2 Flooding onto Five Minerals and Three Porous Media
Authors: Grigg R. B. , Bai B.
Published: December 2007

This paper documents results of adsorption and desorption tests performed onto five powdered minerals and three rock types using a carbon dioxide - aqueous phase foaming agent, surfactant Chaser International CD1045™ (CD). This work was performed in order to better understand surfactant adsorption behaviors and transport mechanisms through three different porous media. Batch experiments were run to determine the kinetics of the surfactant adsorption onto five powdered minerals common to the selected three porous media. Dynamic experiments were performed to determine the kinetics and equilibria of surfactant adsorption onto three porous media. Characterizations of the three porous media were performed by SEM (Scanning Electron Microscopy) to aid in discerning the mechanisms controlling the retention and release reaction rates of the surfactant through the three different rock types.

Results show that CD adsorption and desorption onto powdered minerals can be established in one hour. The decreasing order of the surfactant adsorption density onto the five minerals is: montmorillonite, dolomite, kaolinite, silica and calcite. Surfactant adsorption onto the three core systems took at least an order of magnitude longer than that onto the five powdered minerals, and the surfactant adsorption onto Berea sandstone required a longer time than either Indiana limestone or Lockport dolomite. Desorption of the surfactant from the three porous media follows exponent decline equations.
The Successful Use of Both Kinetic Hydrate and Paraffin Inhibitors Together in a Deepwater Pipeline with a High Water Cut in the Gulf of Mexico
Authors: Swanson T. A. , Petrie M. , Sifferman T. R.
Published: December 2007

Under deepwater operating conditions, hydrates and wax can often form blockages in a pipeline. The resultant costs to remediate the situation include not only those for removing the blockage, but also for lost production.

Potential hydrate preventative measures include Low Dosage Hydrate Inhibitors (LDHIs) which are limited by hydrate formation potential (known as subcooling that is measured in F degrees) and both fluid compositions and ratios. The subcooling for this application is very challenging, since it is between 15 F degrees under normal operating conditions and 27 F degrees under shut-in conditions.

This field application was conducted on a pipeline for a newly re-completed well which was predicted to have water cuts in the 20% range. Actual water-cuts have typically been about 35% but have also increased to above 60% at times.

The continuing evaluation of different chemistries and consequently different mechanisms for preventing hydrate and wax problems in a sub-sea pipeline is reviewed. A kinetic hydrate inhibitor (KHI) was injected after the production rates had stabilized. A wax inhibitor was also used because of previous concerns about possible wax blockage.

The kinetic hydrate inhibitor was chosen based on data from lab testing and computer modeling. Not only is steady state operation often an issue, but shut-down and, more importantly, start-up are often the major concerns. KHIs are classified as LDHIs since only low concentrations (generally below 3%) are used.

The KHI provided lower operating costs plus better environmental conditions than methanol, which had been used before the well was re-completed.

The advantages and disadvantages of this KHI product are reviewed. Some of the advantages of KHIs (compared to methanol) include reduced logistics, removal of the undesirable methanol from the crude, plus no oil/water quality issues.

This continuous injection application in the deepwater Gulf of Mexico is special since KHIs have generally not been used there. Most previous continuous injection case histories have been from the North Sea. Also, wax control additives were used in conjunction with the LDHIs.
Enhancing Chemical Efficiency Using Slow-Release Corrosion Inhibitors
Authors: Weghorn S. J. , Stegmann D. W.
Published: December 2007

The proper application of corrosion inhibitors within oil and gas producing wells is critical so that a timely delivery of chemical occurs throughout the system. In conventional batch treatment, the performance of the chemical and the retreatment interval depend almost entirely upon the film persistency of the product. In continuous treatment, the chemical performance depends on the concentration of inhibitor in the brine phase. By using the new slow release (mass-transfer controlled) encapsulated corrosion inhibitor described in this paper the chemical performance is based both upon the inhibitor concentration in the system and its film persistency. The novel slow-release treatment of encapsulated corrosion inhibitors approximates continuous inhibitor application while providing the film persistency characteristics best attained using a batch chemical application. This results in a chemical treatment that provides highly effective corrosion treatment in wells, especially those that present treatment challenges due to climatic conditions or for those located in remote areas.
Controlling Corrosive Biofilms by the Application of Biocides
Authors: Maxwell S.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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

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.
Rheology of Aqueous Drilling Foam Using a Flow-Through Rotational Viscometer
Authors: Chen Z. , Ahmed R. M. , Miska S. Z. , Takach N. E. , Yu M. , Pickell M. B. , Hallman J. H.
Published: December 2007

Safe and economical foam drilling requires a good knowledge of foam rheology and hydraulics. Compared with traditional incompressible fluids, foam is a thermodynamically unstable fluid and its rheology is rather complex. Compressibility, quality, liquid and gas phase properties, slippage at the wall, etc., can all affect foam rheology. The true rheology of foam has been hidden in many past foam rheology experiments due to the confounding effects of wall slip, mode of foam generation, foam bubble size and size distribution, etc.

This study describes foam rheology experiments conducted using a Foam Generator and Viscometer Apparatus and Process designed and developed at the University of Tulsa (US Patent number US 6,807,849), This process utilizes a flow-through Couette viscometer with roughened cups and rotors at gauge pressure 1.72×105 Pa (25 psig) and temperature 25°C (77°F). This apparatus generates foam with controllable properties and allows the foam to flow through a modified Couette-type rotational viscometer. The flow rate is regulated so that rheology of the foam is determined under constant foam quality (in-situ gas flow volume fraction), pressure and temperature. A visualization cell coupled to an image acquisition device permits structure characterization of the foam in parallel with the rheological measurements.

Wall slip and rheological properties of different foams were studied for different rotor and cup surface roughnesses. Results relating to foam rheology are discussed with emphasis on the effects of foam bubble size, quality and wall roughness. Significant rheology differences are observed for different surface roughnesses, that was explained by wall slip phenomena.
Internal Phase Breaker Technology for Viscoelastic Surfactant Gelled Fluids
Authors: Crews J. B.
Published: December 2007

Past viscoelastic surfactant (VES) gelled fluids used for fracpacking and conventional hydraulic fracturing have primarily relied on external or reservoir conditions to break (reduce) the fluids gel viscosity. This paper describes an internal phase breaker system developed for breaking viscoelastic surfactant gelled fluids. Laboratory rheological data is presented that shows controlled viscosity reduction can be achieved from 80°F to 225°F by the use of two or three aqueous breaker solutions. The mix waters evaluated were KCl, CaCl2, and ASTM synthetic seawater. The results show that break times typical for polymeric fluids can now be achieved for VES gelled fluids.