bluuebunny/crossref_metadata_2025 huggingface dataset:
HCl-Formic In-Situ Gelled Acid for Carbonate Acidizing: Core Flood and Reaction Rate Study
Authors: Rabie Ahmed I. , Gomaa Ahmed M. , Nasr-El-Din Hisham A.
Published: September 2011

Hydrochloric acid has been extensively used for well stimulation in matrix acidizing and acid fracturing. However, high reaction rate and severity of corrosion problems, especially for wells completed with Cr-based tubulars, limit the usage of the straight acid, especially for deep gas reservoirs. In-situ gelled acids are used to reduce leak-off rate and enhance acid diversion, while mixing organic acids with regular hydrochloric acid reduces the strength of HCl and increases the acid penetration. Literature review shows that very few numbers of studies have addressed the systems that utilize both advantages.

The objective of this work is to investigate the effect of formic acid on the performance of the live and the spent in-situ gelled formic-HCl through viscosity measurements and core flood studies and to measure the rate of reaction of different formic-HCl in-situ gelled acid mixtures with calcite. Pink Desert limestone was utilized for the core flood and the reaction rate experiments. The core flood study was conducted at 250°F using two different rates of injection (2 and 10 cm3/min) and the rotating disk reactor was used to perform the reaction rate study. The effect of formic acid concentration, disk rotational speed, and zirconium cross-linking additive on the reaction rate was examined at 250°F. The formic acid concentration ranged from 0 to 6.31 wt% and the HCl concentration ranged from 0 to 5 wt.%.

The core flood results showed that in this acid concentration range with the selected polymer and zirconium cross linking agent, the in-situ formic-HCl acid is behaving more like gelled acid. Increasing the formic acid concentration decreases the reaction rate with calcite at both low and high disk rotational speed. This was confirmed by the viscosity measurements, which showed that increasing the formic acid concentration increased the live acid viscosity and decreased the viscosity of the spent acid.
Effects of Injected Water Chemistry on Waterflood Sweep Efficiency via Induced Fines Migration
Authors: Lemon Phillip , Zeinijahromi Abbas , Bedrikovetsky Pavel , Shahin Ibrahim
Published: September 2011

Permeability decline during corefloods with varying water composition, especially with low salinity water, has been observed in numerous laboratory studies. It has often been explained by the lifting, migration and subsequent plugging of pores by fine particles, which have been observed in numerous core flood tests with altered water composition. In this work, the concept that this permeability decline may be used for mobility control during waterflooding was investigated. The Dietz model for waterflooding in a layer cake reservoir with a constant injection and production rate was combined with a particle detachment model to provide a simple analytical model for the process. The application of the model to an example data set showed induced fines migration may improve sweep efficiency for a given volume of injected water.
Improved Drilling Economics and Enhanced Target Acquisition through the Application of Effective Geomagnetic Referencing
Authors: Poedjono Benny , Olalere Ismail Bolaji , Shevchenko Irina , Lawson Fraser , Crozier Steve , Li Xiong
Published: September 2011

For a deepwater operator facing the challenges of directional drilling and wellbore stability, surveying with high spread costs in excess of USD 1 million per day, any approach which promises to reduce or eliminate cost and risk has great potential benefit. This paper showcases how careful planning, a fit-for-purpose survey program, and, most importantly, an effective, real-time geomagnetic referencing service (GRS) can significantly improve the operator's ability to hit both geological and financial targets. The authors describe recent breakthrough improvements in the accuracy of GRS techniques and present a case study to illustrate the benefits of this approach for the industry, especially in deepwater operations.

Each magnetic survey tool has an associated degree of uncertainty in the accuracy of data acquired. This error is cumulative, increasing with depth as a well is being drilled. In three dimensions, this area of uncertainty takes an elliptical form around the projected well path, a zone of possible well positions known as the ellipse of uncertainty (EOU). In high-angle wells, the EOU may grow so large that it exceeds the dimensions of the geological target, decreasing the driller's level of confidence and increasing the risks and potential costs of missing the target. Therefore, the development of more accurate yet cost-effective surveying techniques has become increasingly critical.

The authors will describe a survey approach that meets this challenge by incorporating breakthroughs in real-time GRS and which offers the producer the following benefits: Achieving planned geological targetsSaving the cost of running gyroscopic surveysAvoiding costly post-gyro well path corrections by staying on-path in real timePreventing stuck pipe, lost time, and other risks often associated with gyro surveys

The example case to be discussed illustrates how to realize all of the above benefits.
Performance Analysis of Recovery Processes for Extra Heavy Oil through Mechanistic Modelling and Simulation
Authors: Foo Y. Y. , Chee S. C. , Zain Z. M. , Mamora D. D.
Published: September 2011

The venture into various unconventional hydrocarbon resources, such as heavy oil and oil sands, has been aggressively undertaken by industrial oil players to satisfy the ever-increasing world energy demand. Heavy oil captures the global attention due to the sheer size of its oil-in-place volume. However, its high-density and high-viscosity characteristics represent a great challenge in terms of recovery optimization. Reservoir modelling and simulation has been widely recognized as an important technique to evaluate recovery efficiency as a function of the reservoir conditions and the type of recovery process.

In this paper, an extra heavy oil reservoir, the Oilfield Alpha, located in Venezuela is selected as the reservoir of interest. Conceptual models of extra heavy oil recovery, categorized into cold and thermal techniques, are addressed. Both of the thermal methods (Steam Flooding, Cyclic Steam Stimulation, Steam Assisted Gravity Drainage, etc.) and cold methods (Horizontal Well, Vapour Extraction, etc.) are studied and modelled using CMG STARS simulator. Performance indicators - typically the recovery factor, oil production rate, Steam-Oil-Ratio (SOR), etc. - for each model are evaluated and compared. The simulation results show that, after 20 years of production, the thermal methods have prevalently higher oil recovery factor, i.e. 7 - 37 % of OOIP compared to that of cold methods, i.e. 8 - 13 % of OOIP. In conclusion, the mechanistic models assist in strategic reservoir development planning at preliminary stage and, in turn, provide enhancement of oil recovery and productivity.
Dynamic Underbalance for Selective Perforation Cleaning from Hard Scale Deposits, Successful and Fully Controlled Case Histories
Authors: Vegliante Enzo , Busaidy Adil Al
Published: September 2011

Presence of water can often be a source of numerous problems, such as mineral scale deposition on well tubing, casing and perforation tunnels.

Abu Attifel, an onshore Libyan oilfield producing since 1972, is a multi-level sandstone reservoir where anhydrite and barite depositions have been affecting production for the past 25 years.

All the wells are cased (5" liner) hole and most of them are completed in more than one layer in commingle (in few wells all the 13 different identified layers are commingled to production).
Comparison of Porosity Estimated from Conventional Logs in Complex Lithologic Reservoirs
Authors: Xiao L. , Mao Z. Q. , Sun Z. C. , Luo X. P.
Published: September 2011

Six main kinds of minerals exist in the interested intervals, they compose complicated lithologies, this leads it is difficult in calculating reservoir porosity accurately by using a unified model. To remove the ambiguity of porosity calculation in complex lithologic reservoirs, two methods are attempted, they are core calibration logging method and optimization method. For the core calibration logging method, formations should be divided into two kinds of argillaceous siltstoue and dolomitic siltstone based on the difference of matrix density firstly, the formulae of these two kinds of formations are established to calculate porosity from density log. The volume physical model is also used for porosity calculation based on the optimization method. The credibility of these two models is verified by the comparison of porosity among calculated from core calibration logging method, optimization method and core analysis results. The calculated results using these two methods are all suitable for the requirement of formation evaluation and calculation of reserves, the absolute error of calculated porosity from core calibration logging method is lower than 0.4%. The optimization method is much more practicable. The principle of core calibration logging method is simply and the operational process is easy, is suggested to be used.
Improved Spacer Rheology Model for Cement Operations
Authors: Olowolagba Kolawole , Yerubandi Krishna Babu
Published: September 2011

In the cementing industry, it is known that zonal isolation is dependent on a successful cement job. To achieve zonal isolation, effective mud removal is recommended (Crook et al. 2001). Efficient mud displacement can be achieved with the use of spacers and flushes before cement is placed. With an increasing need to successfully complete a well on the first try, accurately modeling the spacer rheology has become key.

This paper presents results from a comparison of two rheological models. The Bingham plastic and Generalized Herschel Bulkley (GHB) models examined in this work are both used to model rheologies of spacers. For most field operations, the Bingham plastic model is used to model rheologies; however, studies have shown that using this model can lead to over-predicting yield point. The GHB model is used to model non-Newtonian fluids by incorporating the possibility that the fluid might or might not have a yield stress and that the shear stress might be a nonlinear function of shear rate.

Spacers are used to separate one fluid from another. They are designed to be compatible with the mud being used in the well. This paper compares the performance of spacer and spacer/mud rheologies at different elevated temperatures (200, 300, and 350°F) with measurements from a Model 75 HP/HT viscometer.

Results have been modeled in a computational fluid-dynamics simulator to illustrate the effects of each rheological model used to describe the well-completions fluids. The simulator modeled displacement and intermixing of wellbore fluids downhole, and these are investigated in the annulus for the simulated case.
Optimizing Paraffin and Naphthene Wax-Treatment Options Using Cross-Polarized Microscopy
Authors: Bacon Mark M. , Romero-Zerón Laura B.
Published: September 2011

Wax deposition is a worldwide problem for the upstream petroleum industry. Considerable resources are expended every year on trial-and-error type chemical treatment options. In a laboratory setting chemical treatments are often optimized using viscosity and pour point measurements. Viscometry and pour points can only measure bulk properties. Cross-Polarized Microscopy (CPM), however, has been shown in previous work to be a useful tool to determine individual wax crystal size and morphology. Thus, in this work CPM was used to evaluate the effectiveness of wax inhibitor treatments for paraffinic and naphthenic base oils by monitoring the morphology and size of the wax crystals before and after the application of the chemical treatments.

It has been demonstrated that there is a statistically significant reduction in wax crystal size after the wax treatment. Furthermore, the observations of the wax morphologies through CPM have demonstrated that the chemical treatment effectively inhibits wax crystal growth for both macrocrystalline (paraffin) and microcrystalline (naphthene and iso-paraffin) waxes. In addition to viscosity and pour point measurements CPM has been demonstrated to be a valuable tool to the optimization of wax-treatment options.
The Value of Experience
Authors: Alcoser L..
Published: September 2011

This paper presents an improved technique for the analysis and evaluation of professional development. The oil and gas industry has braced itself for an abrupt shift in workforce expertise as the baby boomer generation reaches retirement age, commonly referred as the "Big Crew Change." The subsequent hiring frenzy observed in the past decade has led to an influx of expectant young professionals. This paper presents a personnel development philosophy for these new young professionals as well as a screening and evaluation methodology that can be utilized during the hiring and promotional process to better select talented, knowledgeable professionals with initiative. A novel metric is also presented to estimate and assign a value to the different experiences that make up a career. Three example applications are given to illustrate the utility of the proposed metric and methodology.
Water-Cut Reduction during Waterflood by Induced Fines Migration: Effects of Varying Formation Damage Coefficient
Authors: Zeinijahromi Abbas , Lemon Phillip , Bedrikovetsky Pavel
Published: September 2011

Decline of permeability during corefloods with low salinity and high pH water, has been widely reported in the literature. It has been explained by the lifting, migration and subsequent plugging of pores by fine particles, which has been observed in numerous core flood tests with altered water composition. This effect can be considered to provide a relatively simple method for mobility control during waterflooding. In previous research, the Dietz model for waterflooding in a layer-cake reservoir was combined with a particle detachment model to investigate the effect of fines migration and induced permeability decline on reservoir sweep efficiency and amount of injected water; the model was derived under the assumption of constant formation damage coefficient. In this work, the model was extended to the case where the formation damage, caused by captured fines, depends on absolute permeability of the rock. The modeling showed that the incremental recovery and reduced water cut, caused by induced fines migration, is lower for the case of formation damage coefficient decreasing with permeability increase, than for the case of constant formation damage coefficient.
Preparation of Novel Amphoteric Flocculant and Its Application in Oilfield Water Treatment
Authors: Song Hui
Published: September 2011

An amphoteric starch-graft-polyacrylamide (S-g-PAM) was prepared by inverse emulsion polymerization, subsequent hydrolysis reaction and Mannich reaction. The effects of reaction conditions on copolymerization and the use of the polymer as the water clarifier in oilfield water treatment were investigated. The application test showed that the results of oilfield waste water treatment by amphoteric S-g-PAM were better than those treated with cationic polyacrylamide (PAM), hydrolytic PAM and amphoteric PAM.
Improved Understanding of Fracturing Tight-Shale Gas Formations
Authors: Bai Mao
Published: September 2011

Because of the special characteristics of the tight-shale gas formations, the conventional concepts of hydraulic fracturing may become irrelevant, and the new concepts must be consequently developed to optimize the stimulation process for the tight formations. This paper focuses on improving the understanding of fracturing tight-shale gas formations through parametric sensitivity analysis of a case study. The concepts of stimulating tight formations were better understood by examining the end impacts of some critical factors, such as: a) leak-off percentage in relation to the tight-shale gas formations, b) screenout in relation to the net pressure signatures, and c) injection rate and proppant concentration in relation to the fracturing efficiency, etc. With reference to these observations, applying the proposed alternative approaches appears to be imperative to enhance the current stimulation technologies for tight-shale gas formations.
Casing Integrity Evaluation in Deep Well with Extreme Heavy Mud in Tarim Basin
Authors: Tian Jun , Wang Qinghua , Guo Qingbin , Guo Hongzhi , Liu Chuan
Published: September 2011

The high dip angle in formations is one of the reasons makes it difficult to drill in Tarim Basin, resulting in much longer drilling time. To counteract the high pressure from the salt layer above the targeted gas zone, 16-mm heavy casing and drilling mud as heavy as 1.9 g/cc must be used. As drill bit and pipes continue repeatedly tripping in and out the well the heavy casing may get wore thinner. Therefore it's important to know the degree of the casing wear, and to recalculate the remaining strength. Furthermore, if channel in cement behind the casing exists across the high pressure layer, it will pose another threat to corrode the casing from outside and reduce the overall strength of the casing. Hence the cement quality behind the heavy casing must be measured and assessed by reliable means. The tradition technology for well integrity evaluation has limitations in providing answers to the casing corrosion and zonal isolation in such challenge downhole condition.

A new generation of the ultrasonic imaging tool was introduced to increase the certainty of casing mechanical property measurement and cement evaluation. The technique combines the pulse-echo ultrasonic measurement with a new flexural wave measurement. The analysis from this combination allows not only a better discrimination between solid, liquid and gas for cement evaluation behind casing, but also more accurate casing information including internal diameter and casing thickness at high resolution in one trip in a well. A logging example was illustrated in this paper with high quality logging data acquired in difficult down hole conditions. As can be seen in this example, many casing grooves were found, and metal loss were up to maximum 4mm at some spots. This paper also shows a new way to look at cement quality behind the heavy casing.
Chemical Modification of Biopolymers to Design Cement Slurries with Temperature-Activated Viscosification
Authors: Reddy B. R. , Patil Rahul , Patil Sandip
Published: September 2011

Polymeric viscosifiers are added to cement slurries for a variety of reasons, including prevention of particle settling and control of fluid loss, gas migration, and free-water. Many of these functions are critically important after the cement slurry has been placed behind the casing but before the setting of the cement. Some functions, such as particle-settling prevention, are also important during the pumping phase. Unfortunately, most of the viscosifying polymers suffer from thermal thinning at bottomhole temperatures, especially under shear. The amount of polymer required to maintain the required level of viscosity at elevated bottomhole temperatures causes excessive surface-slurry viscosification at ambient temperature. Pumping such slurries can require higher pump pressures, or in cases where formation breakdown pressure might be exceeded. This becomes a serious challenge when the window between the fracture pressure and the pore pressure of the formation is narrow. It would be a significant improvement to oilfield cementing technology to develop polymers that do not cause excessive slurry viscosification on the surface but gradually increase the slurry viscosity as it reaches downhole temperatures, with the maximum viscosity reached at the time the slurry becomes static behind the casing.

This paper describes an economical chemical method, not based on encapsulation, for modifying biopolymers and their derivatives—for example, hydroxyethylcellulose, xanthan, and guar—that renders them insoluble in cement slurries at room temperature (RT). When the cement slurries are heated, the slurries develop viscosity, as reflected by rheological measurements. The method also provides for increased viscosification efficiency of the modified polymers because of the increased molecular weights of the modified biopolymer products. Synthesis details, slurry rheologies at different temperatures, and job-placement simulation details are presented. A possible reaction mechanism that is operative in the chemical-modification step is also discussed.
Development and Application of Foamers to Enhance Crude Oil Production
Authors: Lehrer Scott , Debord Saet Byul , Means Carlene , Crosby Simon
Published: September 2011

As petroleum wells age, reservoir pressure and resulting gas velocity decrease. Consequently, the hydrostatic head of fluid in the production tubing increases due to insufficient transport energy from the gas phase to lift the fluid from the well. This can decrease overall production and ultimately cause shutdowns. Initially, this problem can manifest as a production decline over time until production becomes limited; even with a fully open choke. Later, maintaining production can become even more challenging as wells begin to slug and then experience cycling production. Well production can become impossible without the assistance of artificial lift.

In gas fields foamers have successfully increased production by unloading fluid and reducing hydrostatic pressure with little capital investment. While traditional foamers effectively remove water or condensate from gas wells, they are ineffective at foaming crude oil. As there are many applications in crude oil wells where foamer could be a useful artificial lift technique, a research program was undertaken resulting in the development of a novel crude oil foamer. Laboratory testing of a wide range of crude oils and water cuts determined the types of fluid that the new foamer treats effectively. Promising lab results were obtained for fluids with an API gravity range of 25-40° and water cuts up to 60%.

A south Texas EOG Resources well was identified as a potential candidate to field trial the new foamer. Due to low reservoir pressure, this well produces intermittently, cycling on/off every seven days. Historical production rates were approximately 40 BWPD, 40 BOPD, and 250 Mcf/D. However, the well recently experienced a significant production decrease. During the two months prior to applying the crude oil foamer, production declined to only 13 BOPD and 122 Mcf/D.

A field trial at the EOG Resources well demonstrated the crude oil foamer effectiveness at increasing oil and gas production. The foamer was fed at a rate of 750 ppm through a capillary string located near the wellbore. During the trial, continuous production increased from 7 days to 12 days and the average production of oil and gas increased to 100 BOPD and 400 Mcf/D, respectively.
Carbon Dioxide, Geochemical, and Rate-of-Dissolution Simulation for Deep Storage Environments
Authors: Ceyhan Ismail , Santra Ashok , Cullick A. S.
Published: September 2011

Permanent underground storage of carbon dioxide (CO2) has been proposed as a potential mitigator for greenhouse gases in the atmosphere. In such underground reservoirs, CO2 is trapped through a complex combination of physical and chemical processes. Also, injected CO2 in contact with subsurface water can decrease the cement strength, deteriorating wellbore integrity. Current industry programs, such as reservoir simulators and wellbore-cementing programs, provide powerful models for the physical processes. This paper discusses a model for the remaining geochemical processes. This model is designed for implementation in existing industry programs, enabling the industry, while planning carbon capture and sequestration (CCS) projects, to take advantage of experience acquired throughout many years.

A self-contained solution procedure has been developed to solve geochemical equilibrium calculations. The equilibrium within the brine phase is computed with activity coefficients calculated by use of either the general Helgeson-Kirkham-Flowers (HKF) electrolyte model, or the more-accurate Pitzer ion model. A correlation from open literature has been selected to calculate the equilibrium between CO2 and brine phases. Once equilibrium is established, the model calculates precipitation or dissolution rates for common minerals. The solution procedure has been designed for optimum balance between robustness and calculation speed while solving the nonlinear geochemical equilibrium problem. A novel initialization scheme and a three-pass solution procedure are introduced. During Pass 1, activity coefficients are set to unity while a nonlinear minimization algorithm is used to locate the neighborhood of the equilibrium solution; in Pass 2, the first pass is repeated with the activity coefficients being calculated by use of the selected model. Finally, during the final pass, the solution is refined to the desired accuracy by the use of a nonlinear solver.

The solution model fits observed data. The CO2 solubility and brine phase pH can be computed for temperatures between 300K (80°F) and 478K (400°F), pressures up to 414 bar (6,000 psia), and brine strengths up to 6 mol NaCl/kg H2O. The more than 50 primary and secondary mineral species in the database represent common carbonate and clastic formation components. Temperature-dependent dissolution and mineralization rates can be predicted at similar conditions.

As the industry plans CCS projects, it must document projections of formation and well integrity during the project lifetime. The solution procedure is suitable for inclusion in various oil and gas industry models, including cementing simulators or reservoir simulators, to model CCS in subsurface aquifers and enhanced oil recovery (EOR). This paper provides guidance on how the algorithms should be implemented within reservoir simulators.
Gas Well De-Watering Method Field Study
Authors: Haydel Rick D. , Brink Donald J. , Acker William K. , Gassiott Gary J.
Published: September 2011

A common industry problem in many flowing gas wells is the gradual build-up of well-bore fluids across the perforations over time. This phenomenon, commonly referred to as liquid loading, is typically seen in many wells that are low-producing, low in pressure, or have long perforation sets. A new gas well de-watering system has been developed to combat this problem, utilizing the reservoir’s energy to help keep it unloaded. This system utilizes a production packer, tail pipe, and carrier subs containing pressure regulating devices in order to trap and use formation gas to keep the well unloaded beneath the packer. This paper will take a closer look into the system through a study of field examples where it was implemented. In the study, one specific well from the US West Rockies Region will be chronicled from the original diagnosis of the liquid loading problem, to the design and installation of the system. Analysis plots are shown to illustrate its success. Additional field examples, within the same and different US fields, will be included to give further illustrations of this de-watering system, while also exemplifying and detailing the system’s limitations in an unsuccessful installation. A comparison analysis will be included and a discussion of lessons learned. The implementation of this system on properly selected wells can significantly impact the performance of low-producing gas wells where liquid loading destroys productivity levels over time. Although it can be run in conjunction with conventional artificial lift, this system introduces a way of utilizing the reservoir’s energy to keep it flowing naturally for a longer period, before artificial lift is necessary. This helps to reduce the overall well costs at a time when the industry is dominated by many tight, unconventional gas wells.
Biphasic Viscosity Reducers as Production Aids for Viscous Oil
Authors: Faust M. , Weathers Thomas
Published: September 2011

In this report, the development and field deployment of a novel biphasic viscosity reducer will be discussed as a means to enhance production and transport efficiency of high viscosity crude oils while reducing total operating expenditures. Standard flow aids target the root cause of inefficient fluid flow; drag reducers, for example, suppress the turbulence associated with flowing oil, while paraffin inhibitors and asphaltene inhibitors prevent wax crystal or asphaltene particle growth. Biphasic viscosity reducer chemicals target the bulk fluid properties of the crude oil, regardless of the source of viscosity, by dispersing oil into free water, creating a highly flow-able, low apparent viscosity, water external emulsion. Screening tests confirmed the capacity of certain polymers to emulsify heavy oils, with API gravities well below 20, as well as waxy crudes from different locations around the world into 20-25% water solutions, creating stable, water external emulsions. In all cases the emulsion exhibited significant levels of apparent viscosity reduction, generating improved flow- ability in a bench-top flow loop, as well as emulsion resolution under standard field separation conditions including heat and traditional emulsion breaking chemicals. The top-performing products were assessed in a full-scale field trial on a high wax crude oil, where the biphasic viscosity reducer chemical resulted in efficient pressure maintenance for the topsides flow lines over the span of the field trial, significantly reducing operating costs associated with pressure buildup in these lines. Throughout the period of chemical injection, no adverse effects on water quality or oil/water separation were observed at the separation battery.
Scale Inhibitor Application In Northern Alberta - A Case History of an Ultra High Temperature Scale Inhibition Solution in Fire Tube Heater Treaters
Authors: Wylde Jonathan J , Allan Keith , McMahon Jeff , Mayner Steve
Published: September 2011

This paper reports further work performed on a challenging scaling environment in Alberta. Scale was forming on the fire tubes of a series of heater treaters. Bulk fluid temperature was 110°C but skin temperature of the fire tubes was in excess of 450°C. This created an incredibly high scaling potential.

Previous work characterized the scaling on the tubes. This is briefly summarized with an update given on the continued success of this treatment, best practice monitoring results, and optimization. This current work describes the further investigation of the system scaling challenge. It was found that in solving calcite scaling, other scale forms became dominant such as siderite and silica scales. Furthermore, it was found that one of the root causes of scale build-up was the presence of EOR polymer in the produced water.

Laboratory work evaluated the incumbent program for efficacy against siderite scale precipitation using an anoxic test method. Work focusing on the glue-like EOR polymer build-up has also been described, including chemical mitigation and remediation methods. Results showed that the incumbent treatment, whilst optimal for calcite scale, was not optimized for the overall multiple scaling scenario. Furthermore, the EOR polymer fouling mitigation required a totally new and unique treatment approach.

A summary of the field application and results of the new chemical strategy has been given illustrating a clear step change in the frequency of fouling in the production system. The paper concludes with a critique of how the laboratory data was representative of the field application. A final hypothesis is discussed, suggesting that EOR polymer breakthrough was a significant root cause of scale deposition due to the ease of deposition in the process system. Subsequently, this proved influential on the deposition of mineral scale and other solid deposits.
Case Study: Evaluation of an Oxidative Biocide During and After a Hydraulic Fracturing Job in the Marcellus Shale
Authors: Rimassa Shawn M. , Howard Paul , MacKay Bruce , Blow Kristel , Coffman Noel
Published: September 2011

Effective microbiological control is an important aspect of a successfully executed fracturing job. Control of bacterial growth is often accomplished through the use of biocides such as glutaraldehyde, particularly in the multi-stage, high-volume fracturing of unconventional shale gas reservoirs. Biocidal additives, which are toxic by necessity, can persist in flowback water, so their use in shale fracturing has come under increasing scrutiny since high biocide concentrations in flowback water increase fluid cost and limit the options for disposal. The case for designing a bactericide program to match, and not exceed, the required amount of bacterial control is clear, but rarely is the bacterial load determined during and after the job to verify this balance.

Herein, we report a case study undertaken to evaluate the bacterial load of field mix water and flowback water during and after a large hydraulic fracturing job in the Marcellus Shale. A novel oxidative biocide product was used during the fracturing job that has both an effective fast kill and a low toxicity profile (e.g. HMIS rating of 1,0,0). Because of its rapid biodegradability, there was concern that the effective kill of this biocide would not persist beyond a few days. Industry standard techniques (NACE Std. TMO194-94) for quantifying bacteria were applied to water samples taken during the job and over several weeks of production. The biocide was also evaluated for compatibility with common fracturing additives and for its corrosivity to surface equipment and tubular goods.

This study determines that the new biocide does not persist in flowback water beyond a few days. However, analysis of flowback water samples reveals that the bacteria count stays low (less than 10 cells/mL) for up to 81 days after application of this biocide in a slickwater fluid. Additionally, genetic fingerprinting using Denaturing Gradient Gel Electrophoresis Analysis (DGGE) was applied to the bacteria in the initial field mix water to allow comparison to any bacteria detected in the flowback samples. This paper will describe the details of this case study.

Since the completion of this case study, we have successfully deployed this technology on treatments in the Barnett, Haynesville, Marcellus, and Granite Wash shale regions. This paper reveals details of a field test and of the efficacy of this biocide as tested in flowback waters from the Piceance and Marcellus Shale basin. The results of the bacteria enumerated from each job site sample are presented. Finally, dosage requirements for biocidal efficacy were optimized for slickwater hydraulic fracturing applications are described.
Gas Well Deliquification Using Microwave Heating
Authors: Mohamed kamal , Ghodke Nikhil , Patwardhan S. D. , Al-Dogail Fuad
Published: September 2011

One of the challenging problems of gas production is the liquid loading of a gas well. It is the inability of the produced gas to remove the produced liquids from the well bore. This phenomenon has a significantly negative impact on gas well production rate and reservoir pressure due to build up of liquids in the well bore. The accumulated liquid may be in the form of formation water, condensed water or hydrocarbons condensate which acts as a hindrance to the formation gas getting produced. The ultimate recovery of gas is dependent on the economic removal of accumulated liquids, to allow the gas to get produced.

This paper discusses a new idea of using dielectric heating using microwaves to heat and vaporize the water and hydrocarbons in the wellbore, if present. As a result of this heating, the fluid density decreases and the gas and vapours flow naturally to the surface. The frequency of microwaves in general is 2450 MHz; depending on the need, the frequency can be varied. Experiments were carried out on the use of this technology and the results are encouraging. This paper discusses this new technique, results obtained from conducted experiments, and provides advantages to the current methods.
The Effect of Surfactants on the Kinetics of Hydrate Formation
Authors: Ramaswamy Divya , Sharma Mukul M.
Published: September 2011

Dissociation of gas hydrates has been the primary concern of the oil and gas industry for flow assurance, primarily in an offshore environment. There is also a growing interest in the rapid formation of gas hydrates for gas storage, transport of natural gas and carbon sequestration.

In this paper, we experimentally measure the kinetics of formation of methane hydrates and the effect of various anionic and cationic surfactants such as sodium dodecyl sulfate (SDS), cetyl trimethyl ammonium bromide (CTAB) and an alpha olefin sulfonate (AOS) on the association rate constants. The importance and necessity of micelle formation in these surfactants has been studied. The effect of foam generation on the rate of formation of these hydrates has also been measured.

SDS was found to significantly increase the rate and decrease the induction time for hydrate formation. On the other hand, CTAB and AOS have an inhibiting effect. We observed a decrease in the induction time by a factor of ten when a low concentration of SDS was used instead of only de-ionized water and methane. There was an added decrease in the induction time when a foamed mixture of water and SDS was used. The contribution of some types of micelles towards promoting hydrate formation was demonstrated with a series of experiments using SDS and other surfactants. The micelles formed by these surfactants appear to serve as nucleation sites for the association of hydrates.

New experimental data is presented to show that the use of some surfactants and the use of foam can significantly increase the rate of hydrate formation and decrease the induction time. Other surfactants are shown to act as inhibitors. An experimental setup, protocol and analysis method is presented that allows us to distinguish between surfactants that act as promoters and inhibitors for hydrate formation.
Live Fiber-Optic Telemetry Downhole Measurements on Coiled-Tubing-Enabled High-Efficiency Sand Cleanout in a Subhydrostatic Well for the First Time in the Gulf of Mexico
Authors: Rudnik A. , Foinquinos C. , James K. E.
Published: September 2011

Gulf of Mexico (GoM) reservoirs consist mainly of unconsolidated sandstones. Elevated production rates and high near-wellbore fluid velocities increase the possibility of dragging the unconsolidated sand grains into the wellbore and surface production equipment. Formation sand invasion into wellbore is a common problem in the GoM, especially in wells not completed with sand control features or wells where initial sand control failed. Wellbore sand cleanouts, therefore, represent the majority of coiled tubing (CT) interventions in the GoM. As the reservoirs mature, the number of through tubing well interventions (TTWI) in sub-hydrostatic wells is constantly growing. These types of wells cannot sustain a full column of fluid which presents a significant challenge to maintain circulation and sufficient annular fluid velocity required to transport the solids to surface. Nitrified and foamed cleanouts can provide at-balance or slightly over-balanced downhole conditions necessary to minimize the fluid losses into formation. Nitrified cleanouts are normally considered as more cost effective solution which is quite important since most of the sub-hydrostatic wells are very marginal producers. However, planning and execution of nitrified jobs require accurate well information which is not always accurate or available. This drives the operators to make the most common decision; to utilize the more expensive and extensive cleanout technique - the foamed cleanout - in order to ensure job objectives with reduced risks.

Real-time downhole measurements provided by a fiber-optic enabled telemetry CT helps overcome the typical challenges and operational risks associated with sub-hydrostatic well cleanouts; it also helps reduce the overall operational costs by making the job more efficient in terms of time, equipment and product usage. This paper will present a case study of the first optimized CT sand cleanout in the Gulf of Mexico.
Performance Evaluation of a Plunger Assisted Intermittent Gas Lift System
Authors: Bello O. , Falcone G. , Xu J. , Scott S.
Published: September 2011

Several techniques have been investigated to date to alleviate the detrimental effect of liquid loading in gas wells. However, relatively little is known about the theoretical and operational aspects of plunger-assisted intermittent gas lift for gas well deliquification. This study presents an analytical approach for modeling the performance plunger-assisted intermittent gas lift system using conservation equations (continuity and momentum), thermodynamic principles and material balance.

Numerical examples are presented to illustrate the performance of the model using field data. A sensitivity study is then performed to assess the influence of different parameters on the performance of the plunger-assisted intermittent gas lift system.
Novel Drag-Reducing Agents for Fracturing Treatments Based on Polyacrylamide Containing Weak Labile Links in the Polymer Backbone
Authors: Kot E. , Bismarck A. , Saini R. K. , Norman L. R.
Published: September 2011

Water-soluble polymers have found extensive use in the oil and gas industry. For instance, high molecular-weight polymers are very efficient drag/friction-reducing agents and viscosifiers. Unfortunately, the adsorption of the polymer on the reservoir formation reduces the effectiveness of the recovery of oil and gas from tight low-permeability formations, such as shale. The availability of water-soluble polymers containing weak links in the backbone of the polymer that can be degraded upon experiencing a certain trigger, such as temperature, pH, or reducing agent, would be very advantageous. Because of the ability of weak links to degrade under certain conditions, such polymers can be used for their intended application and afterwards be degraded in a controlled and predetermined way. The resulting lower molecular-weight fractions of that polymer lead to reduced viscosity, quick partitioning in the water phase, and they are also less likely to adsorb onto formation surfaces. Additionally, no oxidizers need to be pumped to break or clean the deposited polymer, thus, saving time and money.

It has been proved that using a bifunctional reducing agent containing degradable groups and oxidizing metal ion as a redox couple is a facile method to initiate the free-radical polymerisation and build degradable groups into the backbone of the vinyl polymers. Temperature-degradable but hydrolytically stable azo groups showed the most desirable results. The presence of azo groups in the backbone of the synthesized polyacrylamide (PAM) was confirmed by rf-NMR spectra and differential scanning calorimetry (DSC). The degradation behavior of the PAM with temperature-sensitive azo groups was characterised using gel permeation chromatography (GPC) system and proved the multiple labile links were built into the polymer backbone. It was also found that PAM with azo links in the polymer backbone is as good a drag-reducing agent as pure PAM. However, PAM with azo links in the backbone loses its drag-reduction properties once subjected to elevated temperature, which for some applications is viewed as an advantage.
Surfactant Modeling for Insight into Load-Recovery Enhancement for Fracturing Treatments
Authors: Gdanski Rick , Funkhouser Gary P.
Published: September 2011

Load recovery from fracturing treatments in tight-gas sands is often considered to be an important indicator of success. Poor load recovery is often associated with poor performance, and used to invoke water blocks as a damage mechanism. Surfactants are designed and used to enhance load recovery, presumably by capillary pressure effects. A fit-for-purpose fracture cleanup and chemistry simulator (FCCS) was improved to study the impact of surfactant adsorption, surface-wettability changes, and surface-tension reduction on load recovery from hypothetical fracturing treatments.

The simulator was improved by adding surfactant adsorption/desorption kinetics, wettability functions that were dependant on the amount of adsorption, and adsorption capacities. Simulations were conducted as a function of fracture conductivity, matrix relative permeability (rel-perm) quality, and various surfactant properties. It was found that surfactants have the greatest impact when matrix rel-perm functions are of moderately good quality or better. Surface-tension reduction alone tended to simply enhance imbibition, while changing wettability to near non-wet substantially enhanced load recovery. Fracture conductivity had a substantial role because it determined whether imbibition or drawdown won the battle over water movement. The methodology of the surfactant modeling is presented, along with the results from numerous simulations.

This work demonstrates that surfactants can enhance load recovery under certain circumstances, with wettability changes being most important. However, matrix rel-perms must be of sufficient quality that capillary effects are able to overcome viscous effects.
Ultra-HTHP Scale Control for Deepwater Oil and Gas Production
Authors: Fan Chunfang , Shi Wei , Zhang Ping , Lu Haiping , Zhang Nan , Work Sarah , Al-Saiari Hamad A. , Kan Amy T. , Tomson Mason B.
Published: September 2011

Scale control in deepwater oil and gas production is often challenging due to not only the geological and mechanical limitation associated with deepwater wells, but also the high temperature (>150°C) and high pressure (>10,000 psi) environment, which may be associated with brine containing high total dissolved solids (TDSs > 300,000 mg/L or greater). These extreme conditions make scale prediction, control and testing difficult because of the requirements for special alloy, pumps and control equipments that are not readily available. Therefore, very few reliable ultra-HTHP data are available. To overcome such challenges, an efficient flow-loop method has been established to study both the equilibrium and kinetics of scale formation and inhibition at ultra-HTHP conditions. This paper will discuss (1) an efficient flow-loop method to study the solubility of scale minerals at ultra-HTHP conditions; (2) solubility of barite at a temperature up to 200°C and pressure up to 20,000 psi; and (3) scale control and inhibitor selection for deepwater oil and gas production at ultra-HTHP conditions. Specifically, the performance and thermal stability of some common scale inhibitors at the high temperature conditions were studied in terms of barite inhibition. The results to-date indicated that (1) the solubility of barite at up to 200°C and 24,000 psi can be precisely measured by this newly developed flow-loop apparatus; (2) the rate of mineral scale formation at HTHP may be considerably faster than previously projected from low temperature studies and hence, difficult to inhibit; (3) different scale inhibitors have shown considerably different thermal stability. The results and findings from these studies validate a new HTHP apparatus for scale and inhibitor testings and information for better scale control at HTHP condition.
Souring Treatment with Nitrate in Fields from which Oil is Produced by Produced Water Reinjection
Authors: Voordouw G. , Agrawal A. , Park H. S. , Gieg L. M. , Jack T. R. , Cavallaro A. , Granli T. , Miner K.
Published: September 2011

Nitrate can control souring in fields with high bottom hole temperature (BHT) and where sulfide is produced in the near-injection-wellbore-region (NIWR). The objective of the treatment is to lower the sulfide concentration in produced water and oil, reducing corrosion risk in producing wells and above-ground infrastructure. Achieving this objective can be problematic for fields with low BHT or for fields in which the reservoir contributes sulfate to the produced water, as is demonstrated by analysing three PWRI case studies. Nitrate was found to effectively oxidize sulfide in produced waters, even when excess oil organics were present. An alternative strategy that should be considered is, therefore, to inject nitrate in the produced waters in a dose corresponding to the sulfide concentration.