bluuebunny/crossref_metadata_2025 huggingface dataset:
Synthetic Polymer Fracturing Fluid for High-Temperature Applications
Authors: Funkhouser Gary P. , Norman Lewis R.
Published: December 2007

High-temperature fracturing fluids based on guar degrade rapidly at temperatures above 300°F, complicating stimulation of high-temperature wells. A synthetic polymer was developed that overcomes the hydrolytic stability limitations of polysaccharides while maintaining the ability to crosslink and break the fluid.

This paper presents the initial laboratory development of a fracturing fluid using the synthetic polymer. Hydration is rapid compared to guar, eliminating the need for special hydration tanks or equipment when mixed on-the-fly. Crosslinking is achieved with conventional zirconium crosslinkers to yield a highly viscoelastic gel. Static and dynamic fluid-loss test data are presented and compared to guar-based fluids. Dynamic effects on fluid-loss rates were negligible compared to a borate-crosslinked guar fluid over a wide range of matrix permeabilities. Rheological characterization up to 400°F was performed with a Fann Model 50 viscometer and clearly demonstrated the synthetic frac fluid's high stability relative to guar. Additionally, effects of various breaker types are presented.
New Surfactant for Chemical Flood in High-Salinity Reservoir
Authors: Zaitoun Alain , Fonseca Claudio , Berger Paul , Bazin Brigitte , Monin Nicole
Published: December 2007

Evaluation of the chemical flood potential in the Chihuido de la Sierra Negra field, Argentina, has been carried out using several different recovery scenarios. This field has been submitted to extensive waterflooding for several years, and surface facilities have been designed to recycle produced brine as injection brine. The use of produced brine, as chemical solution make-up water is therefore very advantageous from both an operational and economical point of view. However, the formation brine contains around 110,000 PPM Total Dissolved Solids with around 2,800 PPM divalent cations. This makes the selection of the proper surfactant extremely difficult. Processes such as Alkali Surfactant Polymer Flooding have been considered, however, the requirement of large amounts of fresh water as well as softening units in the field adversely affects the economics of this process.

This paper will discuss the development of a new anionic surfactant that provides solubility in high salinities and low interfacial tension at low concentration. The Chihuido de la Sierra Negra field history will be briefly described, and the laboratory screening and evaluation of the surfactants, including the interfacial tension properties, the adsorption, the core evaluation, and the performance of the flood will also be discussed.

The significance of this development is that it could lend feasibility to EOR projects that would be deemed uneconomical because of water treatment and handling costs.
A Circulating Foam Loop for Evaluating Foam at Conditions of Use
Authors: Hutchins Richard D. , Miller Matthew J.
Published: December 2007

Foam stability is an important parameter for foamed fracturing. Bench-top testing is useful for screening but does not address the necessary conditions of temperature, pressure, pH (particularly with carbon dioxide [CO2] systems) and dynamic flow conditions which can have unexpected influence on the foam's performance.

A laboratory apparatus has been constructed for measuring the rheology of circulating foam fluids to 400°F and 2000 psi. The apparatus is equipped with a circulation pump, view cells, foam generator, mass flowmeter and piping for loading a foam of the desired quality using either nitrogen or CO2. The foam rheometer is intended for evaluation of foam stability with time and comparison of various foam formulations for application in foam fracturing.

The foam loop was designed to mimic shear rates found in a fracture or reservoir, which are typically 200 s-1 or less. The rheology is measured by monitoring the pressure drop across a 20-ft length of ¼-in. tubing maintained at temperature in an oven. Flow rate is continually adjusted to ensure a constant shear rate in the tubing by the software using continuous mass flowmeter input.

Results relating to CO2 and nitrogen foams are discussed with emphasis on foam persistence, bubble size and population, and the rheological behavior with time. Temperature, pressure, and additives affect both foam texture and foam stability. The adoption of a standard technique patterned after this work for evaluating foam rheology could impact the use and development of foam fluids in the future.
Improved Transportation of Waxy Crude Oils and Emulsions in Bekasap Area, Indonesia
Authors: Tang Y. , Shuler P. J. , Cheug S. K. , Goodgame J. A. , Hsu J. J. , Padilla A. V.
Published: December 2007

One challenge in the production of oil fields in the remote Bekasap Area of Indonesia is the transportation of waxy crude oils through long pipelines. The current practice is to add hot water to the oil so fluids remain well above the pour point temperature of the crude (90 – 105 °F). This, however, limits oil-carrying capacity and increases costs due to handling and separating oil/water mixtures. This study focused on understanding the causes of the high pipeline pressures and to develop more economic transportation strategies. Laboratory measurements included oil/water emulsion rheology over a wide span of conditions, wax/gel formation, and the effect of various chemical treatment additives. A customized spreadsheet program was developed to model the current pipeline operation and to predict the change in pipeline pressures/temperatures under different scenarios.

The results indicate that the formation of relatively high viscosity oil/water emulsions is the most likely cause for the high pressure losses in these flowlines. Laboratory measurements demonstrate these oil/water mixtures have a complex physical nature and rheology. Simulations indicate the potential benefit of reducing the mixture viscosities via chemical treatment or heat management. For the Pinang Field, which was studied in the most detail, adding insulation to bare pipe areas provided a successful solution.
Removal of Water Soluble Organics from Produced Brine without Formation of Scale
Authors: Hart Paul R.
Published: December 2007

Water Soluble Organics (WSO) are included in the measurement of Oil and Grease (O&G), a conventional pollutant controlled by the Clean Water Act. WSO partition to the produced brine at the production pH but to the extraction solvent used to measure the O&G at the test pH of < 2. The predominant chemical species comprising WSO in Gulf of Mexico crude oil brines are medium chain carboxylic acids. Chemicals can be added to desolubilize these species in conjunction with treatments to remove the resultant emulsion. For a variety of reasons, the most reliable and cost effective desolubilization agents have proven to be the non-volatile, multi-protic oxy acids (e.g. HxSOx and HxPOx). However, in the presence of divalent cations in the brine, these form insoluble scale deposits. Moreover, in the presence of WSO in mixed production, this scale becomes oil wet and uninhibitable. A new treatment comprising a new class of desolubilizer in conjunction with certain polymers has now been shown to be equally reliable and cost effective without the formation of scale even at extreme concentrations of divalent cations. The chemistry is explained and case histories chronicled to illustrate its effectiveness in the field.
Effect of Dispersion on Transport and Precipitation of Barium and Sulfate in Oil Reservoirs
Authors: Delshad Mojdeh , Pope Gary A.
Published: December 2007

The incompatibility of injected saline seawater and formation water is the primary cause of scale deposition in offshore developments. Many offshore oilfields are encountering problems with barium sulfate precipitation due to the mixing of sulfate-anion-rich seawater and formation brine with excessive amounts of barium cation. A mechanistic physico-chemical modeling approach is required to predict the amount of scaling to assist operators in making decision regarding scale prevention in oil reservoirs. The predictive model allows various types of flow scenarios to be investigated to reduce the amount of scaling and prevent well damage and eventual loss of well productivities.

Three-dimensional field-scale simulations were performed to investigate the flow and transport of barium and sulfate ions and the significance of barium sulfate precipitation in a typical offshore oil reservoir. The reservoir simulator has the modeling capability of multiphase flow, water reaction chemistry and interaction with the rock, and more significantly the species transport equations that include physical dispersion. The reactions were kept simple with barium and sulfate ions as the only reacting species and sodium, chloride, and calcium ions as non-reacting species. Barium sulfate was considered as the only solid precipitate. Simulations were performed to determine sensitivity to dispersion and mixing in the reservoir, to determine how much solid precipitates in the reservoir and in the wellbore, and to estimate how much sulfate needs to be removed from the injected seawater to prevent the formation damage.
The Impact of Chemical Incompatibilities in Commingled Fluids on the Efficiency of a Produced Water Reinjection System: A North Sea Example
Authors: Stalker Robert , Collins Ian R. , Graham Gordon M.
Published: December 2007

The current practice of overboard discharge of produced water from offshore facilities is becoming increasingly less attractive owing to environmental concerns and the impact of more stringent regulations. An alternative to overboard discharge is produced water re-injection (PWRI) into depleted reservoirs or into non-communicating aquifers. However, as offshore developments become more complex, with new fields producing through existing facilities, PWRI must face the problems involved in combining and re-injecting incompatible fluids and/or production chemicals. In this paper we describe a laboratory testing programme which was devised to aid in the development of a PWRI scheme for a North Sea facility. In the proposed re-injection scheme, produced waters from five fields are combined at a central facility prior to re-injection. Initial brine/production chemical compatibility tests identified potentially problematic incompatibilities. A series of formation damage core floods were performed to investigate the effect of these incompatibilities on injectivity into reconditioned reservoir core material from the proposed re-injection well. These tests were followed by further core flooding work in which alternative solvent-based strategies for the amelioration of incompatibility issues were investigated. From this sequence of tests emerged a PWRI protocol suitable for advancement towards field trials.

This paper describes typical problems encountered in the development of multi-well produced water re-injection projects using commingled waters produced from different fields containing potential incompatibilities both from the co-mingled brines themselves and also as a result of the diverse range of treatment chemicals present in the individual production streams. The strategies employed to overcome these problems in this field case are discussed.
Drag Reduction-Performance in Laboratory Compared to Pipelines
Authors: Hamouda A. A.
Published: December 2007

Flow assurance in pipelines is enhanced by the use of long chain polymers having average molecular weight of many orders of magnitude over 106. This makes them susceptible to shear degradation in oil pipeline systems, hence loss of performance. In order to be able to scale-up the drag reduction efficiency tests from laboratory to full-scale pipeline, it is important to design the laboratory test experiments to address pipeline parameters such as flow regime, shear rates, temperature and pressure changes. It is impossible to include All the parameters in one test, as the case for the actual pipeline systems where all these parameters are interacting simultaneously. However, designing experimental tests that make bridges between these parameters may offer a compromising solution(s) addressing certain conditions.

The work done in this paper is related to defining the major parameters and validates some of the used theories to establish the flow regime envelops. Prandtle Karmen theory and Virk's, maximum drag reduction asymptote are combined to define the onset envelops in transition from one regime to another in presence of the polymer drag reducers. A Three-process approach has been developed to evaluate the degradation in terms of rheological behavior and drag reduction efficiency. Some case studies are re-visited to explain some of the observations.
A Systematic Approach for Experimental Study of Asphaltene Deposition for an Abu Dhabi Reservoir Under WAG Development Plan
Authors: Negahban S. , Joshi N. , Jamaluddin A. K. M. , Nighswander J.
Published: December 2007

This paper discusses experimental work associated with the evaluation of asphaltene deposition for a field in Abu Dhabi, UAE. The subject reservoir is in the early stages of development and will be put on production using a combination of gas, water, and water aleternating gas (WAG) injection schemes in early 2006. The field has not shown operational problems resulting from asphaltene precipitation during primary production.

Laboratory experiments using the transmittance of an optimized laser light in the near infrared (NIR) wavelength (∼1,600 nm) were used to first confirm the stability of asphaltene in the reservoir fluid. Two cases, covering the expected extremes in terms of the field gas/oil-ratio (GOR) were evaluated. Isothermal depressurization tests were also conducted at reservoir, wellhead, and separator temperatures (250°, 190° and 130°C).

Several additional light transmittance experiments were conducted to evaluate the asphaltene instability regions resulting from reservoir fluid contact with various concentrations of a rich gas and carbon dioxide (CO2). Measurements using high-pressure filtration were also conducted to quantify the bulk precipitation of asphaltene with various molar concentrations of gas.

Finally, tests were conducted using state-of-the-art technologies to evaluate the consistency of the initial NIR runs. These technologies involved the use of a spectral analysis system (SAS) to evaluate the asphaltene particles size and growth rate and high-pressure microscopic images to visually confirm the measurements.

Results indicated that rich hydrocarbon gas, in contact with reservoir fluid, destabilizes asphaltene. The amount of the bulk precipitation increased with higher concentrations of rich gas in the reservoir fluid. Particle sizes were in the range of 0.5 to 1 micron and did not pose any threat to plug pore throats, and consequently did not affect the recovery potential. The effect of CO2 was found to be less severe with regards to asphaltene instability.
Cloud Point and Wax Deposition Measurement Techniques
Authors: Leontaritis Kosta J. , Leontaritis John D.
Published: December 2007

Paraffin-waxes present in crude oils, at some thermodynamic states, exhibit the phenomenon of crystallization. The onset of wax crystallization temperature of stock tank oil at atmospheric pressure is known as the cloud point. In this paper, cloud point data are presented for several synthetic mixtures and crude oils. The cloud point data have been obtained via three different techniques: Near-Infra-Red (NIR) light attenuation, Dynamic Filtration Cloud Point (DFCP), and ASTM-D2500. For the transparent mixtures, the ASTM-D2500 method is being used as the standard against which the other two techniques are compared to. The data show that all three techniques are consistent with each other, although their precision is different. Because of its simplicity, higher precision, and wide applicability to all kinds of fluids and thermodynamic conditions, the NIR light attenuation technique is recommended.

Furthermore, cloud point and wax deposition data from a variation of the DFCP technique are presented from various crude oils from around the world. Some of these oils contain natural asphaltene dispersants and wax crystal modifiers and as a result, although these oils contain substantial amounts of asphaltene and wax molecules, they remain stable at most thermodynamic conditions encountered during their production. Two cases of these "special" oils are presented here.
Application of Nonionic Tenside Homologues in IOR/EOR and Oilfield Chemistry: Fundamental and Engineering Aspects
Authors: Lakatos I. , Lakatos-Szabó J. , Bedo Zs.
Published: December 2007

The paper gives an overview on the application of Nonionic surfactants in hydrocarbon industry, particularly oil production. Advantages and disadvantages are critically analyzed in field of recovery and well treatment methods, drilling and well completion, surface technology and pipe line transportation. On the basis of the literature survey it is concluded that the practice oriented R&Ds performed during the past half century were not sufficiently supported by fundamental physico chemical and colloid chemical research. In the second part of the paper the authors give a concise summary of their studies aimed at forming a theoretical basis of wide range applications of ethoxylated nonyl-phenols in oilfield chemistry. The research program comprised the thermodynamic characterization of micellization, determination of micelle and solution structure, effect of different additives, interfacial properties in gas(water and oil(water systems and the effect of tensides on interfacial rheological properties. The microscopic approach and molecular interpretation of the observed phenomena allowed the authors to recommend more precisely where, when and which of the tensides have the highest potential in different oilfield applications.
Identification of Mechanisms and Parameters of Formation Damage Associated with Chemical Flooding
Authors: Patino Omar , Civan Faruk , Shah Subhash N. , Zornes David R. , Spinler Eugene A.
Published: December 2007

This paper presents a practical methodology and its verification for determination of the mechanisms and parameters of chemically induced formation damage. It is based on interpretation of laboratory core flood tests by diagnostic straight-line plotting schemes. Laboratory tests were conducted to measure the permeability impairment and effluent conditions as a function of time by flooding sandstone and limestone outcrop rock samples with various alkaline solutions (NaOH, KOH, NaSiO4) and alcohol (ethanol) as might be used for improved oil recovery. The single-phase permeability variation data were plotted according to prescribed diagnostic straight-line plotting schemes proposed by Wojtanowicz et al. and Civan. Plots that result in satisfactory straight-line trends reveal the predominate mechanisms of the formation damage. Further, the values of the parameters of the governing formation damage processes are determined from the intercept and slope of the straight-lines. Higher pH solutions were observed to have caused greater reductions in rock permeability. Civan's model better described the permeability variation due to scale dissolution and precipitation processes. The Wojtanowicz et al. model identified the formation damage mechanisms as pore surface deposition and sweeping. Different rock damage conditions were observed for the initial and the later test periods, indicating that more than one formation damage mechanism was involved. The analysis of the same experimental data reveals that a numerical model such as UTCHEM will require significantly more information to perform a similar analysis of the laboratory flood results. However, the diagnostic equations provide a practical and rapid means for the determination of the formation damage mechanisms.

The methodology developed in this paper can be used for rapid detection and quantification of the formation damage mechanisms from core tests. The technique can be useful in the design of alkaline-surfactant-polymer (ASP) and/or micellar flooding chemical systems for field applications.
Effect of Brine Dilution and Surfactant Concentration on Spreading and Wettability
Authors: Vijapurapu Chandra S. , Rao Dandina N.
Published: December 2007

The interfacial phenomena of spreading and adhesion of fluids on rock surfaces have serious implications because of their impact on production strategy and oil recovery. The present study reports new experimental data on the effect of brine dilution and surfactant addition on spreading and adhesion behavior of Yates crude oil on dolomite surfaces. Spreading and adhesion have been characterized through measurements of oil-water interfacial tension (IFT) and dynamic (water-advancing and receding) contact angles. The interfacial tension was measured using Computerized Axisymmetric Drop Shape Analysis (CADSA) Technique, which was calibrated against the well-known du Nuoy Ring Technique. The Dual-Drop-Dual-Crystal (DDDC) Technique has been used to measure dynamic contact angles.

In order to study the effect of brine dilution, Yates reservoir brine was mixed with deionized water (DIW) in various proportions. For each diluted brine, crude oil-water IFT, water-advancing and receding contact angles were measured. The oil-water IFT initially decreased as the volume percent of brine in the mixture decreased. However, the IFT increased with further dilution of reservoir brine with DIW. A decreasing trend was observed in the behavior of water-advancing contact angle with brine dilution. This indicated that the initial oil-wet nature of the system was changed to intermediate-wettability simply by diluting the reservoir brine. However, a strange behavior of spreading of crude oil drop against brine on the dolomite surface (with large water-receding contact angles) was observed at certain brine dilutions. This spreading of crude oil appears to be related to interfacial tension in a manner similar to Zisman's observations in solid-liquid-vapor systems.

The use of surfactants to enhance oil recovery through reduction in IFT is well known in the industry. However, this study examines the capability of certain surfactants to alter wettability in addition to reducing IFT. For the Yates reservoir rock-fluids system, an Ethoxy Alcohol surfactant altered the strongly oil-wet nature (advancing angle of 158°) to water-wet (advancing angle of 39°) at a concentration of 3500 ppm. While the DDDC technique yielded significant changes in wettability due to surfactant addition, the Wilhelmy Plate Technique remained insensitive throughout the range of surfactant concentrations. The practical significance of this study is that it identifies two simple modes through surfactant addition and brine dilution to alter wettability to minimize capillary trapping of oil.
A Way Beyond Scale Inhibitors – Extending Scale Inhibitor Squeeze Life through Bridging
Authors: Selle Olav M. , Wat Rex M. S. , Vikane Olav , Nasvik Haavard , Chen Ping , Hagen Thomas , Montgomerie Harry , Bourne Hugh
Published: December 2007

The Heidrun Field is located in the Haltenbanken area offshore Mid-Norway. The reservoir temperature is 85 – 88 °C and the reservoir pressure is close to hydrostatic pressure, around 250 bar. Seawater injection is utilized to increase recovery and for pressure support. With Ba2+ levels averaging about 200ppm, downhole sulphate scale deposition caused by seawater injection has been identified. The field came on stream in 1995. Heidrun presents a particular challenging scaling environment due to the combination of high Ba2+ content, demand for environmental friendly chemicals, strong top-side emulsion tendency, limited hydrostatics and at times high draw down within the gravel packs. In addition, the high kaolinite content (20–30 %) in the reservoirs introduces the risk of fines mobilization leading to plugging within the gravel packs especially with the development of overflush fluids volumes used during squeeze treatments. Scale control started in November 1999 with regular squeeze treatments. However, initial squeezes suffered from short treatment life and evidence of fines related productivity decline.

Under a joint R&D program, a multi-functional additive was developed that enhanced inhibitor adsorption, provided clay stabilisation and a certain level of scale inhibition.

This paper presents both laboratory and field data to elucidate the mechanisms involved in extending squeeze life and clay fines stabilization with this additive.
Application of a Thermo-Kinetic Model to the Prediction of Scale in Angola Block 3 Field
Authors: Rousseau G. , Hurtevent C. , Azaroual M. , Kervévan C. , Durance M. -V.
Published: December 2007

Block 3 reservoirs in Angola are dolomitic reservoirs with temperatures ranging from 150 to 164 °C with a nearly constant pressure (320 bar). They are all affected by scale precipitation that forms into the tubings and the topsides.

Modeling was applied to find quick correlations between physical measurements and the predicted risk of scaling. Information from wire line reports, maintenance operations and gamma campaigns were gathered in order to draw up a list of risky wells, and to validate the found correlations. The water cut, the composition of the produced water, the well head temperature and the drawdown can be used to determine the risk of scaling and roughly the location of the deposits. In this paper, on one hand, we present the relation between drawdown, water cut and Calcium carbonate precipitation and on the other hand between salinity and barium sulphate scaling.

The kinetic module of the SCALE2000 software was used to explain why the injected seawater does not produce any Calcium carbonate inside the tubing even if it is supersaturated at surface conditions. Finally, a new version of this software has been tested; it includes a model that uses simplified hydrodynamic approach based on a scheme of chemical reactors connected in series.

The model thus takes into account the cumulated effects of water flow in terms of Pressure and Temperature variations, and changes in dynamic water composition due to the mixing. It is then possible to estimate both the thickness of the scale deposits and their location along a production or injection well.
Optimization of a Novel Emulsified Scale Inhibitor System to Mitigate Calcium Carbonate Scale in a Sandstone Reservoir in Saudi Arabia
Authors: Nasr-El-Din H. A. , Saiari H. A. , Hashem M. K. , Bitar G.
Published: December 2007

Description of Paper

Calcium carbonate scale was detected in several vertical wells in a sandstone reservoir in Saudi Arabia. The scale was detected downhole, plugging gravel packing screens and the intake of submersible pumps. Scale build up caused significant decline in oil production from this field. The sandstone reservoir is water-sensitive and has a bottom hole temperature of 160°F.

An emulsified scale inhibitor (phosphonate-type) treatment was designed to mitigate scale in this field. Recently, Nasr-El-Din et al.1 discussed the development of this new treatment and reported initial field results. So far the treatment was successfully applied in more than twenty wells. Some of these wells were de-scaled before the treatment, while other wells were treated before scale detection.

The objectives of the present paper are to assess the outcome of this treatment based on field data and to optimize the scale squeeze treatment based on the analysis of well flow back samples. Samples of produced water from these wells were collected and analyzed for nearly three years.
Naphthenate Scale Formation – Examination of Molecular Controls in Idealised Systems
Authors: Dyer S. J. , Graham G. M. , Arnott C.
Published: December 2007

The formation of calcium naphthenate precipitates and emulsions during oil production is becoming an increasing problem to the oil industry. Naphthenic acids, R-CO2H, are present in many crude oils and the hydrophilic nature of the carboxylic acid group means that they congregate at the oil-water interface. As the pressure drops during production and carbon dioxide is lost from solution, the pH of the brine increases, which in turn leads to dissociation of the naphthenic acid (RCO2H –> RCO2–). The naphthenates can then act as natural surfactants leading either to stabilised emulsions or solid deposits following complexation with calcium cations present in the aqueous phase. The naphthenate deposits collect predominantly in oil / water separators and de-salters but can also deposit in the tubing and pipelines.

This study has looked at a variety of conditions to determine when certain carboxylic acids will form naphthenate deposits under idealised laboratory conditions. A range of naphthenic acids of different molecular structure were dissolved in an organic phase (toluene) and mixed with synthetic brines containing a range of calcium concentrations typical of oilfield production waters. These tests have determined that as the size of straight chain carboxylic acids increases so does the amount of naphthenate deposit. Increases in brine pH also increased the amount of deposit. However, the effects of changes in calcium concentration and molecular structure on the formation of naphthenate deposits were more difficult to quantify. The work assists in increasing our understanding of the factors controlling the precipitation of naphthenate solids under controlled conditions and forms the basis for future studies in real oilfield fluids.
Scale Inhibitor Squeeze Treatment in a Tight Carbonate Reservoir - Problems and Solutions
Authors: Al-Qahtani A. M. , Nasr-El-Din H. A. , Raju K. U.
Published: December 2007

Calcium carbonate scale was detected in the majority of wet producers in a tight carbonate reservoir in the northern part of Saudi Arabia. Extensive lab work indicated that a phosphonate-type scale inhibitor was effective in mitigating carbonate scale, as well as sulfate scale that were found in a few wells. Field application of conventional scale squeeze treatment in this field is not an easy task for the following reasons: The formation is tight and water blockage is a serious concern.Formation brine contains high Ca concentrations (up to 19,930 mg/L).The formation contains high TDS (up to 231,262 mg/L); therefore measuring low concentrations of the phosphonate inhibitor is a real problem.Nearly 70% of the field is offshore, which imposes limitation on the volume of fluids that can be used.

As a result of these challenges, several modifications were introduced to conventional scale squeeze treatments, where a large amount of aqueous phase is typically introduced into the formation. Coreflood experiments were used to evaluate various available options to reduce the amount of aqueous phase introduced into the formation and associated problems. Based on the results obtained from these tests, significant changes were introduced to the preflush, main treatment, postflush, and soaking time.

The new modifications were applied at two wet producers in this field. Well Z-C is a vertical well with 70 vol% water cut, 218°F bottom hole temperature, and 78,540 mg/L TDS. Well B is a horizontal well with 5 vol% water cut, 235°F bottom hole temperature and 209,828 mg/L TDS. An extensive wellhead-sampling program was conducted to measure residual scale inhibitor in the produced brines.

Both wells responded positively to the treatment. The new modifications have resulted in better well response. Analysis of phosphonate in the wellhead samples was used to determine the MIC for this field.
The Acid-IER Method – a Method for Selective Isolation of Carboxylic Acids from Crude Oils and Other Organic Solvents
Authors: Mediaas Heidi , Grande Knut V. , Hustad Britt M. , Rasch Anita , Rueslåtten Håkon G. , Vindstad Jens Emil
Published: December 2007

The amount of acidic crude oils produced worldwide is increasing. These oils introduce problems throughout the hydrocarbon value chain due to their high content of carboxylic acids, examples of which are naphthenate deposition in production facilities and refinery corrosion. In order to deal with these problems, it is often necessary to isolate the carboxylic acids in different fluid streams or solids to allow further analysis without interference from other compounds.

This paper presents and verifies an ion-exchange method that can be used for selective isolation of carboxylic acids from crude oils, distillate fractions and other organic solvent. The efficiency and selectivity of the method have been demonstrated as >98 mol-% using two synthetic carboxylic acids. Its usefulness for isolation of carboxylic acids from solids and non-organic solvents has also been demonstrated, exemplified by calcium naphthenate deposits and water.
Steerable Hole Enlargement Technology in Complex 3D Directional Wells
Authors: Rodman Dave , Wong Thomas , Chong Adrian C.
Published: December 2007

The paper describes application of steerable, hole-enlargement technology in a complex 3D directional application. Following repeated failure of Bi-Center bit technology to meet demanding requirements in a number of offshore East Malaysia wells, the Near Bit Reamer (NBR) was used in a variety of BHA configurations to drill six wells for Shell Malaysia-EP. Cuttings Bed Impeller (CBI) tools were also included in the drill string to facilitate hole cleaning and maintain hole quality. The resultant hole profiles enabled good cement bonds to be achieved for the 7⅝" "SMART" liners, and excellent gravel pack results for the 4½" production liners.

In addition to achieving hole enlargement in a single run, compared to multiple-trips for reaming, use of the NBR and CBI tools provided a fast, clean hole that allowed good casing runs. To date, the NBR tool has been utilized on more than 11 highly deviated wells with no stuck BHA occurrences, where prior experience without the NBR/CBI tools produced at least one stuck BHA per well.

Furthermore, efficient hole enlargement operations in this application allows for SMART completion options, with 7⅝" liner instead of 7" liner for multiple completions that allow selective production, an option that was not possible prior to this.
Mercury in U.S. Crude Oil: A Study by U.S. EPA, API and NPRA
Authors: Wilhelm S. Mark , Kirchgessner David
Published: December 2007

The United States Environmental Protection Agency (U.S. EPA), in cooperation with the American Petroleum Institute (API) and the National Petrochemical and Refiners Association (NPRA), has initiated a project to determine the mercury content of crude oil processed in the United States. The focus of the project is to determine the mean concentration and range of concentrations of mercury (total) in crude oil in a statistical fashion. Data generated in the course of the project will be used to estimate an upper limit to the contribution of mercury in crude oil to anthropogenic mercury emissions in the United States. Portions of the project are examining analytical issues, determining concentration variance in crude oil streams and building a database on total mercury concentrations in crude oils processed in the United States.

Limited data are reported that compare three analytical methods used to measure total mercury content in crude oils. The data demonstrate expected analytical method variance, detection limits and mercury species sensitivities. Aspects of the work in progress address questions concerning sampling methods, sample stability and mercury concentration variability in crude oils having a generic market identity. The plan for statistical sampling of crude oils processed in the U.S. is described in general terms.

In addition to the environmental issues, mercury in crude oil has an impact on its market quality (price). Measuring mercury concentrations in crude oil is now becoming more important as mercury's impact on production and processing systems becomes better understood. The EPA/API/NPRA project should assist development of sampling and analysis methods for crude oil and also will assist researchers to study the distribution of mercury in produced fluids throughout production and processing systems.
Hydrocarbon Impacted Soil and Waste Remediation
Authors: Deuel Lloyd E. , Holliday George H.
Published: December 2007

Improper remediation of hydrocarbon releases to soil or hydrocarbon impacted oil and gas field wastes results in conditions that, at the least, cause tension between lessors and surface owners and the operator. Further, unsatisfactory remediation may lead to legal conflicts, which wastes both natural and capital resources. Fortunately, agricultural techniques are available by which most hydrocarbon releases and adverse environmental impacts can be corrected.

The available petroleum hydrocarbons [TPH] remediation methods include biotreating, composting, dilution, dilution burial, road spreading, reuseable resource technology and ultra-violet ray treatment. This paper discusses land treatment and dilution only, because of the authors' desire to provide an in-depth presentation. Other remediation techniques will be discussed in subsequent papers. Typically, acceptable residual TPH concentrations are attained with land treatment within six months. Dilution is even faster.

Most remediation papers provide case histories describing the results of a particular remediation project. Seldom do these papers provide the technology by which the reader can apply the method to another situation. This paper discusses the theory and design aspects of land treatment TPH remediation. The authors conclude remediation to acceptable residual concentrations can be accomplished at most locations. This conclusion is based on the assumption, oil and gas regulators accept time-tested residual concentrations for TPH, e.g., 10,000 to 30,000 mg/kg. Lower concentration can be achieved, but generally are not warranted on an environmental risk basis.
Changes In Texas Air Emission Grandfathering Rules
Authors: Trout Leonard , Johnstone J. E.
Published: December 2007

The Texas Commission on Environmental Quality (TCEQ) formerly Texas Natural Resource Conservation Commission (TNRCC) is presently implementing new rules to permit Grandfathered facilities in Texas. This will have tremendous impacts for the oil and gas industry. Oil and gas facilities that were once exempted from New Source Review (NSR) under the Grandfathered rules will have to obtain permits and have required control equipment installed in accordance with the new regulations. This paper describes the anticipated rule requirements and discusses the impacts and compliance measures on the oil and gas industry.

Grandfathered facilities are sources of air pollution that were operating prior to the beginning of the Texas New Source Review (NSR) Permitting program. These facilities were exempted from the NSR permitting program. Generally these are facilities that were constructed prior to August 30, 1971.

Exploration and production operators may find that they have many sources of facilities that were "grandfathered." Grandfathered facilities may include compressor engines, gas treating equipment, tanks, flares, vents or other equipment that did not need to be permitted then, but does require a permit now. A good "rule of thumb" when determining if you need a permit is to decide whether, if you were installing that equipment now as a new item, if a permit would be required.
Production of Pipeline Quality Natural Gas with the Molecular Gate® CO2 Removal Process
Authors: Wills James , Shemaria Mark , Mitariten Michael J.
Published: December 2007

In May of 2002, the first Molecular Gate®–Carbon Dioxide Removal system for the removal of carbon dioxide and water was started-up at the Tidelands Oil Production Company operated facility in Long Beach, California. The feed source for the unit is hydrocarbon rich, water-saturated, associated gas from water flood enhanced oil recovery operations. The feed CO2 concentration varies widely and is typically over 30% while the unit reduces the carbon dioxide level to less than 2%. The unit removes the carbon dioxide, heavy hydrocarbons and water producing pipeline specification gas for sale to the local natural gas utility company.
Successful Utilization of Performance Fluids Management in Gulf of Mexico Region 6 Assures Environmental Compliance
Authors: Rojas J. C. , Schonacher D. , Gharst J. , Paiuk B. , Billon B.
Published: December 2007

Meeting the new Gulf of Mexico NPDES environmental regulations (maximum 6.9% oil-on-cuttings), while simultaneously improving drilling performance has been achieved through the implementation of a Performance Fluids Management (PFM) process. This paper describes the creation and application of a fit-for-purpose GOM PFM process, which is a management process that integrates all fluids and waste management-related activities.

This paper will show how the new NPDES (National Pollution Discharge Elimination System) regulation (maximum 6.9% oil on cuttings) was met without impacting drilling operations, while at the same time reducing costs 8 % ($3.5 million) in 2001. Key components of the PFM process include implementation of a common format for fluids management programs; establishing and defining key performance indicators; end-of-well recaps; a weekly PFM report capturing target and stretch performance measures; PFM audit process; skills assessment tools for fluids and PFM engineers; and a model to predict accurate PFM cost/volumes generated.

In order to achieve the objective of reducing the oil-on-cuttings to meet regulatory requirements, the PFM seven-step process was utilized. This process includes expectations, analysis, modeling, setting goals, planning, execution and reviews.

The reduction of oil-on-cuttings (OOC) from 14% to less than 6.9% in the GOM was a very important objective to improve the quality of the discharges to reduce environmental impact. It was very important that drilling performance should be maintained or improved.

The PFM process integrates fluids and waste management. This paper discusses the application of the PFM process.

The authors will present figures showing the following improvements:

Reduction in days per 10,000 ft Reduction in oil-on-cuttings (OOC) Reduction in downhole mud losses Reduction in actual cost compared to AFE Increased mud recovered

The PFM process has been implemented in Colombia, Bolivia, Argentina and Trinidad, where it delivered similar savings.

The process is applicable to wells in excess of $7 million total cost.
Meeting Zero Discharge Requirements in the Gulf of Mexico Using a Unique Cuttings Transport System
Authors: Schonacher D. , Rojas J. C. , Gharst J. , Paiuk B.
Published: December 2007

Zero discharge regulations for non-aqueous drilling fluids used in EPA Region 4 of the Gulf of Mexico have changed the way operators manage drilling fluid and cuttings waste handling and disposal, especially in deepwater. These regulations were considered heavily during the planning stages of two deepwater wells in Desoto Canyon. This paper describes the development and application of the unique cuttings transport and management project that resulted in two successful wells being drilled in EPA Region 4 with no spills, accidents, or negative impact to drilling operations. In addition, when compared to conventional skip-and-ship operations, this system eliminated over 500 crane picks during the course of the two wells. Accordingly, a detailed installation survey was conducted for the assigned drilling vessel
Gas Well Performance at Subcritical Rates
Authors: Sutton Robert P. , Cox Stuart A. , Williams E. Glynn , Stoltz Ronald P. , Gilbert John V.
Published: December 2007

Gas wells producing late in their life are normally subject to liquid loading problems. As rates fall below the critical rate necessary for unloading, a static liquid column will often develop in the well. This can result from condensed water out of the gas phase or formation water being produced into a well having insufficient gas velocity to clear the liquid from the wellbore. The presence of this liquid column impairs the well performance by imparting additional back pressure on the reservoir. The water saturation around the wellbore can increase causing a reduction in the near well effective gas permeability which further compounds the problem of keeping the well unloaded. Traditional methods of evaluating well performance do not properly capture this phenomena; therefore, the existence of additional back pressure on the reservoir can go undetected. Wells continue to produce, but at a reduced rate because of the liquid column. Numerous analysis techniques are available to model static liquid columns in wellbores. A review of these methods and an evaluation of these techniques is presented. Comparisons with field data are made to ascertain the accuracy of the methods and to select an appropriate method to model well performance. Incorporation of this method into a well design allows for the optimization of well productivity.
Design Optimization of a Rotary Gas Separator in ESP Systems
Authors: Harun A. F. , Prado M. G. , Doty D. R.
Published: December 2007

This paper presents the optimization study of a rotary gas separator (RGS) in ESP systems by improving the performance of the inducer part of the RGS. Using two-phase flow inducer model, sensitivity studies were performed to three inducer blade geometrical variables, i.e., tip diameter, pitch length, and total number of pitch, to evaluate the inducer performance in terms of head generation and gas handling capacity.

These studies show that the inducer performance is sensitive to the blade tip diameter and pitch length. Increasing the blade tip diameter and pitch length enlarges the inducer cross sectional area, which in turn increasing the liquid deceleration. This mechanism is responsible for increasing the head generated by the inducer and the sustainability of the inducer in handling free gas. These studies also indicate that increasing the total number of pitch causes detrimental effect to the inducer performance.

These findings suggest that the tip diameter should be made as large as possible within the tolerable size of the pump housing. Similarly, the pitch length should be extended as long as possible within the mechanical integrity tolerance of the whole RGS assembly.

The implementation of the inducer performance sensitivity study results on a typical 400 series RGS indicates that the RGS performance can be improved by enlarging the inducer blade tip diameter and the pitch length. However, the improvement becomes marginal as the gas-liquid ratio increases, which might indicate the limitation of the 400 series RGS application.