bluuebunny/crossref_metadata_2025 huggingface dataset:
On the Partitioning of Hydrogen Sulfide in Oilfield Systems
Authors: Burger E. D. , Jenneman G. E. , Carroll J. J.
Published: June 2014

Hydrogen sulfide (H2S) is a toxic, corrosive gas found in many oilfield production systems. While it can be indigenous to both gas and oil fields, it is also generated in real time within the reservoir by sulfate-reducing bacteria as a result of injecting sulfate-containing water during waterflood. Production of this biogenerated H2S is many times unanticipated and consequently causes operational problems associated with corrosion, safety and satisfying pipeline specifications. While measurement of the H2S concentration in gas is relatively straight forward, the quantitative determination of total H2S mass rate actually being produced in multi-phase systems involves knowing the concentrations in the oil and water also. Partitioning of H2S between the oil, water and gas is a thermodynamic process that is a function of the temperature, pressure, fluids composition, and water pH and ionic strength. The effect of pH is especially important, especially when the pH is neutral or basic for high water cut systems. At these conditions the amount of H2S dissociating into HS− and S= ions, which will remain dissolved in the water phase and will not partition to the oil and gas, becomes significant and will not be reflected in measuring only the concentration in the gas. This paper presents the relationships describing the partitioning of H2S and will provide examples of oilfield systems demonstrating the effects of the operational parameters on determining total H2S mass production rates. The H2S partitioning algorithm described in this paper has been incorporated into a reservoir souring forecasting model, which has been used to evaluate the impacts of operational alternatives on H2S production.
Improvements in Environmental Profile and Cost Effectiveness of Scale Squeeze Inhibitors – A Case Study From the North Sea
Authors: Johnston Clare , Elrick Morag
Published: June 2014

A field in the Central North Sea produces oil from a Forties type reservoir with seawater pressure support. The high salinity formation water contains up to 450mg/l barium, creating a significant scaling risk to the wells, all of which now show seawater breakthrough.

The operator was required to replace a scale squeeze inhibitor carrying a substitution warning, and the need for a more cost effective squeeze lifetime was also a driver for change in a field containing complex wells with highly variable permeability, and a challenging placement environment.

Evolving environmental legislation in the North Sea has forced changes in the type of scale inhibitor which may be deployed in the UK and Norwegian continental shelf. Phosphonate scale inhibitors have been on the substitution list or phased out for some years, leading to a technology gap for scale squeeze applications, where polymer inhibitors often show relatively poor squeeze lifetimes or can be difficult to detect readily at residual concentrations compared to phosphonates.

This paper presents the laboratory evaluation and field application to several wells of the new scale inhibitor, describes the application of the scale inhibitor in complex wells using a combination of placement techniques such as crossflow balancing during shut in and diversion using wax, illustrates that the new inhibitor has demonstrated improved retention and desorption characteristics leading to longer squeeze lifetimes while highlighting the disadvantages of relying on wellhead scale inhibitor analysis alone for scale management of heterogeneous wells.

This paper will illustrate the possibility to replace traditional phosphonate scale inhibitors which carry a substitution warning with a chemical which shows much improved squeeze lifetimes over traditional polymer alternatives, leading to a reduction in campaign frequency and resultant cost savings. The lesson learned from these applications can be shared with other subsea producing basins such as those found in offshore Gulf of Mexico, Brazil and West Africa.
Environmentally Friendly Emulsion Breakers: Vision or Reality?
Authors: Kaiser Anton
Published: June 2014

With the ever-growing demand for more environmentally friendly oilfield chemicals, classic oilfield chemistries are no longer acceptable and new chemical systems are required. Future oil production will still require efficient dehydration and desalting of crude oil. In addition, the protection of the affected environment will be of increased significance.

The industrial availability of ethylene oxide in the 1940s firstly allowed the design of nonionic surfactants for emulsion breaking. With the development of ethylene oxide / propylene oxide block copolymers, the first highly efficient crude oil demulsifers were available. The addition of ethylene oxide / propylene oxide to alkylphenol formaldehyde resins and to oligoamines yielded emulsion breakers that performed sufficiently at low concentrations.

To achieve the future requirements of environmentally acceptable oilfield chemicals, emulsion breakers with low toxicity and high biodegradability are needed. Due to the fact that nonionic alkoxylate based polymeric surfactants have in general a low toxicity, biodegradation was identified as the major bottle neck. Above described polyether type chemistries usually show low biodegradation due to their high molecular weights, especially in marine biodegradation tests (OECD 306) which are often required. Alkylphenol resins have an improved biodegradation profile in comparison to the polyether types, but some serious toxicity issues.

Polyesters are well known as highly biodegradable polymers with low toxicity and a lot of effort was made to design polyester based demulsifers. This paper describes the development of biodegradable alkoxylated polyester dendrimers for breaking oil/water emulsions.
Determination of Multiple Scale Inhibitor Residuals in Single Produced Waters: A Case History From the North Sea Differentiating Four Chemistries
Authors: Wylde Jonathan J. , Savin Adam , Kerr Jamie , McLean Audrey , Duncan Marion
Published: June 2014

With wet tree developments now outweighing dry tree developments in the North Sea, the challenge of accurate surveillance of scaling in wells is increasing. Often, multiple wells feed into manifolds which themselves feed into comingled systems.

The need to differentiate multiple scale inhibitor molecules in the same sample of produced water is now essential in order to monitor the scale health of any given well in that system. Accurate surveillance can save potentially millions of dollars of deferred oil production, intervention vessel hire and chemical and operational costs.

This paper details a case history from the North Sea where the subsea field was located 21 km from the host platform. The field comprised three wet tree wells that each required scale inhibitor squeezing, and the flowline itself also had a scale inhibitor injected at the manifold. Commingling occurred at a manifold and with no test line all fluids were produced to the same dedicated separator on the host platform, which was the further point upstream where sampling could occur.

Details are given on the selection methodologies employed to determine the most appropriate chemistry for each squeeze application, as well as for subsea injection to the manifold. The primary aim was differentiation of all the chemistries from one another. The paper shows how squeeze treatment volume and frequency were optimized, leading to increased production up-time and deferment of chemical costs. It also shows the accurate detection of scale inhibitor to very low levels, providing confidence that the wells remained protected with no scaling or loss of production. All chemistries selected were also done so with the environmental classification in mind, which led to a significant improvement in environmental profile and impact footprint.
When To Batch and When Not To Batch: An Overview of Integrity Management and Batch Corrosion Inhibitor Testing Methods and Application Strategies
Authors: Wylde Jonathan J. , Reid Melanie , Kirkpatrick Alistair , Obeyesekere Nihal , Glasgow David
Published: June 2014

Batch corrosion inhibition has been a technique used for many decades. Often, a non-structured philosophy is taken to treat downhole production tubing and pipelines using batch treatment. This results in non-optimal chemistries and application parameters being employed, resulting in dubious protection being provided as part of an integrity management strategy.

Many of the challenges come down to the different types of evaluation techniques in the laboratory for batch corrosion inhibitors. Furthermore, accurate modeling of batch corrosion inhibitor application is not performed and the application parameters are not optimal; this all results in non-efficient or non-effective protection being provided to the steel of the system.

This paper reviews the different types of methodology used to evaluate batch corrosion inhibitors in the laboratory, ranging from the simple copper sulfate displacement method to advanced electrochemical techniques. Subsequently, it illustrates how the laboratory data can be entered into advanced modeling routines to design the most cost-effective and high-performing application. The paper then gives a case history discussing the different approaches that can be taken for testing and application.

The conclusions of this study show how using the most appropriate testing methodology and modeling can contribute to a much more efficient and appropriate chemical integrity management strategy. The conclusions identifythat the chemical application method into the target system is absolutely crucial to success. The lessons learned from this paper can be used by engineers to optimize their integrity management strategies where batch corrosion inhibition is the mainstay tool for control of corrosion.
Halite Scale Formation Mechanisms, Removal and Control: A Global Overview of Mechanical, Process and Chemical Strategies
Authors: Wylde Jonathan J. , Slayer Jubal L.
Published: June 2014

Halite scale has long been a challenge in the oil and gas industry. In recent years there has been a marked increase in the occurrence of this scale type due to the increased development of hotter and deeper gas and gas condensate fields. As the formation of this scale is commonly in the downhole production tubing, it is a challenge to identify and mitigate, so a non- conventional approach has to be taken for removal and control. Furthermore, it is very difficult to replicate the formation of this scale in the laboratory with complex and specific equipment being utilized to replicate field observations.

This paper provides a review of several examples of halite scale formation in the field, detailing the mechanism of deposition and the strategies employed to remove and subsequently prevent reoccurrence. Details are also provided for two different types of laboratory test methods; the first being a simple static test method designed to quickly screen the extent of halite challenge and the suitability of a range of inhibitors. The second laboratory method concerns a novel, dynamic method whose primary aim is to accurately measure and predict the severity of scaling in the field, and then go on to determine the minimum effective dose of inhibitor required to prevent build-up.

The different types of halite inhibitor chemistries are evaluated, including the use of wash water and where this is used in combination with organo-ferrous compounds, as well as more novel polymeric compounds. The paper concludes by providing an insight into the economics of the different types of treatment, namely the use of wash water versus the use of chemical inhibitors and combinations of these two techniques.
Quantifying Increased Corrosion Risks in Chemical Injection Lines and Gas Lift Systems Due to Partial Evaporation Effects
Authors: Bowering Deborah , Goodwin Neil , McCall Matthew , Stalker Robert , Graham Gordon
Published: June 2014

The application of production chemicals downhole via dedicated injection lines or by means of gas lift systems, whilst not new, is becoming more commonplace in the oil and gas industry. The corrosion characteristics of injected chemical formulations in such systems can be complex and require detailed testing to understand the behaviour and assess the potential corrosion risk of chemical formulations under the extreme conditions of temperature and pressure that exist within either of these injection systems.

In the presence of a fast flowing stream of hot gas, the more volatile components can be stripped from the formulated product, resulting in separate condensed vapours and chemical residues. Similarly, low-pressure vapour pockets formed within downhole chemical injection systems due to hydrostatic pressure fluctuations may cause some components of the injected chemical to be evaporated. Materials compatibility tests are commonly conducted using samples of "as supplied" production chemicals However, there is also a risk that different material compatibility/corrosivity characteristics can be induced by the condensed vapours or stripped residues of the production chemicals when compared to the originally applied chemical formulation. Laboratory testing is not commonly conducted to assess this behaviour.

Samples have been prepared and corrosion tests conducted on collected vapours and residues from production chemicals. Distillations were conducted on the neat chemicals to obtain vapours and residues, and corrosion rates were measured on a range of different metallic specimens by conventional electrochemical or coupon weight loss methods. The results of these separated phase corrosion tests were then compared with the corrosion measurements on the original formulations.

The test programme demonstrated that for some of the formulations tested, significantly higher corrosion rates were measured for either the condensed vapours or the distillation residues when compared to the original formulation.

This work highlights the need to carefully consider the possible range of temperature/pressure conditions and gas/liquid phase interactions that will be experienced by injected chemicals within the chemical delivery system. Specifically, there is a need to assess the implications of solvent stripping/evaporation of volatile components. Chemicals that form more corrosive condensed vapours or residues may need to be avoided to prevent equipment failure or a loss of integrity. It is not adequate to simply test the ‘stability’ of a chemical at elevated temperatures, ambient pressure and static conditions; the separation effects within the gas/liquid system must also be considered.
Development of Peracetic Acid (PAA) as an Environmentally Safe Biocide for Water Treatment During Hydraulic Fracturing Applications
Authors: De Paula Renato M. , Keasler Victor V. , Li Junzhong , McSherry Dave , Staub Rich
Published: June 2014

In the past years, unconventional oil and natural gas production has steadily increased in the United States. Driven by the development of new technologies such as horizontal drilling and hydraulic fracturing, shale gas has led to major increases in reserves of oil and natural gas. During hydraulic fracturing, water and chemicals are injected, at high pressure, into the formation to increase the fractures in the rock layer and allow hydrocarbons to flow. Because large quantities of water are used during this process, the need for water treatment and reuse has become critical. Water treatment prevents the introduction of microorganisms in the formation, which can potentially result in problems such as reservoir souring, biofouling and microbiologically induced corrosion (MIC). Additionally, cleaning of produced water reduces the constant demand for fresh water. Based upon these concerns, we have developed an improved formulation of the oxidizing biocide peracetic acid (PAA). To determine the potential use of PAA in fracturing application, we conducted a number of tests in laboratory and field conditions. We found that this improved chemistry shows superior results when compared to other conventional biocides (glutaraldehyde, THPS, etc), including faster and persistent microbial kill, lower corrosivity, water cleanup properties and solids dropout. We also found that PAA had no adverse effects on other chemistries present in the frac fluids, such as friction reducers and scale inhibitors. Additionally, PAA is a "green" chemistry as it breaks down into innocuous components. Altogether, PAA represents an extremely efficient and environmentally safe option for treatment of water used for hydraulic fracturing.
Stability Investigation of Low-Tension Surfactant Floods
Authors: Lu Jun , Pope Gary A. , Weerasooriya Upali P.
Published: June 2014

Classical stability theory can be used to estimate the critical velocity of a miscible flood stabilized by gravity forces. However, stability theory for an ultra-low interfacial tension (IFT) surfactant displacement is not well developed or validated. In this paper, a method for predicting the critical velocity for a surfactant flood is proposed taking into account the microemulsion phase. Vertical upward surfactant displacement experiments were performed and compared with stability theory. The proposed theory and experimental results offer new insight into the behavior of surfactant floods stabilized by gravity forces.
The Effect of Shale Chemistry on Gas Production Decline in Hydraulically Fractured Shale Gas Wells
Authors: Hassanpoor D. , Hayatdavoudi A. , Boukadi F.
Published: June 2014

Shale gas has become an increasingly significant source of natural gas in the United States. It is puzzling to many that most of the shale gas wells decline very rapidly. Our study shows that in hydraulic fracturing of shale-gas wells operators often use "slick water". The "slick-water", as carrier fluid, comprises plain water and some combination of polymer gel, gel breakers, cross-linkers, and surfactant or surfactant/water alone. However, in lessons learned from the oil field personnel and our own years of research and field practice, we see that first Polymers in general upon hydration retain a water layer for a long time, second Shale absorbs or allows this water layer in the shale body under suction (negative) pressure, then, it converts the suction pressure to swelling pressure reaches which closes the micro fractures, and third, to complicate the matters, some surfactants simply disperse the shale-clays. The net effect of these mechanisms is rapid production decline.

One of the most important mechanisms is water absorption. Shale absorbs water due to the capillary effects of micro fractures and the shale-clay potential. However, there is no model to show the relationship among capillary effect, the shale-clay type potential, the morphology of the shale aggregate, and finally the production decline. We propose a model which connects the above mentioned four elements together and shows the way to the root cause of rapid production decline.

Based on the results we conclude: first the proposed model shows a good correlation between the above four elements in terms of shale fractal dimension and the shale hydration index, all used for calculating the excess hydration stress, and second the excess hydration stress accelerates micro fracture closure, hence the rapid gas production decline.

The benefits of our work follows: one is the combined HHI and the shale fractal dimension can be used to optimize the shale hydraulic fracture conductivity toward long term gas production and the other is the correlation offered here shows it to be a better method for measuring the shale-water activity by using the shale characteristics, namely, the shale water content, the Hydration Index, and the shale fractal dimensions.
The Effect of Surfactants on Vertical Air/Water Flow for Prevention of Liquid Loading
Authors: Van Nimwegen A. T. , Portela L. M. , Henkes R. A.
Published: June 2014

From field experience in the gas industry, it is known that injecting surfactants at the bottom of the well can prevent liquid loading. To increase understanding of surfactant selection, laboratory experiments of air-water flow at atmospheric conditions were performed, where two different surfactants (Sodium dodecyl sulfate and Trifoam 820 Block) were added to the water. In the experiments, a high-speed camera was used to visualize the flow and pressure drop measurements were performed. Both surfactants increase the pressure drop at high gas flow rates and decrease the pressure drop at low gas flow rates. The minimum in the pressure drop moves to lower gas flow rates with increasing surfactant concentration. This is related to the transition between churn and annular flow, which is shifted to lower gas flow rates due to the formation of an almost stagnant foam substrate at the wall of the pipe. At high surfactant concentration, it appears the churn flow regime is no longer present at all and there is a transition from annular flow to a regular slug flow. The results also show that both the critical micelle concentration and the equilibrium surface tension are poor predictors of the type and concentration of surfactant required to decrease the pressure drop.
Pore-Size Dependence of Fluid Phase Behavior and Properties in Organic-Rich Shale Reservoirs
Authors: Didar Behnaz Rahmani , Akkutlu I. Yucel
Published: June 2014

Because of commodity pricing, the production from organic rich shales such as Barnett, Woodford, Eagle Ford and Marcellus has shifted significantly away from the dry natural gas window into the more profitable condensate and liquid hydrocarbon (oil) windows. The current production practices, however, are based mainly on field experience of the operators and far from being a methodological approach for an optimized production. This is mainly due to the fact that our understanding of condensation, capillarity and multi-phase flow dynamics in shale reservoirs is at an infancy stage. It is currently not known, for example, if and where the condensation takes place in the reservoir, and what is the impact of the shale matrix on the this phenomenon. In this paper we argue that answering these questions using conventional laboratory measurement techniques is a difficult task because the fluid properties and the phase behavior of the hydrocarbons could be influenced by the nanoporous nature of these rocks.

Monte Carlo simulations are conducted to investigate pure hydrocarbon vapor-liquid coexistence and critical properties under confinement. The results show a pore size dependence of these thermo-physical properties. Phase diagrams generated using ternary (C1, C4, and C8) mixtures under reservoir conditions show a two-phase envelop shift due to pore size dependence. We show the importance of the results performing a shale gas in-place calculation using Ambrose's equation where the equation of state parameters, z-factor, gas formation volume factor, and adsorbed-phase density values are all adjusted for a range of effective pore size. The corrections on the free and the sorbed gas in-place estimates are significant. Furthermore, we predicted reserves from wet gas, condensate, and volatile oil reservoirs using compositional flow simulation. It is shown that the liquid production from nanoporous rocks is enhanced due to a significant decrease in the bubble point and dew point pressures.
Can We Use Some Methods To Design Surfactants With Ultralow Oil/Water Interfacial Tension?
Authors: Zhu Youyi , Hou Qingfeng , Wang Zhe , Jian Guoqing , Zhang Qun
Published: June 2014

With recent advances in chemical combination flooding, the demand for high performance EOR surfactants is rapidly increasing. One of key parameters of the surfactants used in chemical combination flooding is the ability to decrease interfacial tension (IFT) between crude oil and displacing fluid to ultra-low level (10−3 mN/m). Most of time we use try and error method to screen surfactants, and now we begin to use molecule design theories to select reasonable surfactant molecular structure. Molecule design theories of surfactants, including Hydrophilic-Lipophilic Balance (HLB) value of surfactant, R-ratio (ratio of interaction energy of surfactant and oil with surfactant and water in interface layer), Molecule Geometry Packing Parameter (MGPP) and Quantitative Structure-Property Relationship (QSPR) were introduced and their application for oil displacement surfactants was discussed.

HLB value equal around 6-9 can be used for primary designing and screening of oil-displacement surfactants, which is very convenient. By using HLB empirical equation, the hydrophobic group carbon chain of some of surfactants such as alkylbenzene sulfonate and alkyl naphthalene sulfonate can be optimized. R-ratio, MGPP, QSPR methods can be used in fine designing of oil-displacement surfactants. These methods consider more details of molecule interactions among surfactant, oil and water at interface layer. R-ratio method is still limited by the fact that some interaction energies cannot be measured experimentally. The packing parameter P of MGPP methods can be calculated base on Gibbs adsorption equation with model oil and water. The coincident ratio of MGPP methods for designing oil-displacement surfactants with ultra-low oil/water IFT is high based on 20 surfactants or surfactant mixtures. The correlation model between IFT and molecule structure parameters was established and the coincident ratio of QSPR methods for designing of oil-displacement surfactants with ultra-low IFT of hexadecane/water is good based on 39 surfactants.

Based on molecule design theories, the structure characteristic of surfactants for chemical combination flooding should mainly focus on branch chains, double trails alkyl and/or aryl sulfonate surfactants, zwitterion surfactants, branching chain nonionic-anionic surfactants, gemini surfactants and so on.
Sealing Quality Of Cementing Systems To Be Used on Carbon Capture & Storage CCS Wells
Authors: Tiemeyer C. , Echt T. , Lesti M. , Plank J.
Published: June 2014

Carbon capture and storage (CCS) is considered to be one of the most effective ways to dispose of CO2 generated in coal or gas fired power plants. Cementing such CCS wells presents a technical challenge since ordinary Portland cement (OPC) is known for its corrosion potential with CO2. Such corrosion involves formation and crystallization of CaCO3 from Ca(OH)2 which is formed during the hydration of cement. Furthermore, CaCO3 can be leached as Ca(HCO3)2. This process can create channels in the cementitious matrix for CO2 migration to the surface.

Here, three Portland cement based systems were formulated with different mineral and chemical admixtures and compared with a common API Class G oil well cement with respect to CO2 stability. The systems investigated were based on various concepts. For one cementing system, the aim was to fill the pore space in the cementitious matrix with inorganic, CO2 inert particles while the second was treated with a number of chemical admixtures, particularly latex polymer, to achieve the same goal. The third system was based on slag cement (CEM III) formulated with fly ash.

Hardened specimens (30×50 mm) of the four cementing systems were prepared and stored under supercritical CO2 at 90 °C and 400 bar for one and six months, respectively. The autoclave was half filled with a synthetic reservoir fluid, thus allowing storage in a CO2 saturated salt brine and in wet supercritical CO2 atmosphere. Ingress of CO2 into the hardened cement specimens was probed via phenolphthalein test.

From all systems, only the slag cement (CEM III) blended with a reactive filler (fly ash) exhibited good CO2 resistance. This cement contains a specific ratio of SiO2:CaO which produces only a minor amount of portlandite which can carbonate. For the other cement samples, severe corrosion was observed. The cement system containing chemical admixtures and the neat API Class G system even exhibited severe cracking as a result of high crystallization pressure during CaCO3 growth. Still, carbonation rates were relatively low (~ 0.5 m/year).

The major finding of this study is that common API oil well cement sufficiently withholds CO2 attack if formulated in such way that only minor amounts of CaCO3 are formed, and if the w/c ratio is high enough to provide sufficient pore space for expansion of CaCO3 crystals.
Shale Inhibition: What Works?
Authors: Gomez Sandra , Patel Arvind
Published: June 2014

Understanding the behavior and responses of shale to shale inhibitor additives of drilling and completion fluids has been a challenge for many years because of the numerous and complex chemical and physical variations present in these type of formations. This paper presents the results of laboratory experiments that show how the integration of the geological aspects can help to understand the different responses of the shale to fluids and improve the selection of chemical additives for clay inhibition.

Many of the chemical inhibitor additives have been developed in the laboratory through systematic methods with the use of "standard clay-rich rock samples". These rock samples have relatively simple geologic characteristics and predictable behaviors. The responses of these types of rock samples tend to be consistent and appropriate for evaluations where chemistry of the additives is manipulated constantly. However, the application of these additives goes beyond this approach. In the field, applications target formations that can vary significantly in composition and structure, and simplicity is an uncommon condition. Therefore the challenge for clay stabilization is to integrate many more aspects that can influence the response of the shale formation to fluids.

The paper will present the preliminary process of analysis and understanding of the geologic characteristics of the rock samples and the importance of this fundamental step to achieve the chemical clay stabilization objectives. The paper will include various cases of the inhibitor selection process for shale samples with different characteristics. Chemistry and geology perspectives will be used to analyze the results of the experiments including cases with typical and atypical responses of shale samples. This approach is used to provide a more comprehensive and meaningful interpretation of the rock structural failures due to rock/fluid chemical interactions and, in the same manner, explain how chemical solutions can be used to minimize and control rock instability.
A New Organic Acid To Stimulate Deep Wells in Carbonate Reservoirs
Authors: Al-Douri Ahmad F. , Sayed M. A. , Nasr-El-Din H. A. , Aften Carl
Published: June 2014

Carbonate acidizing has been carried out using HCl-based stimulation fluids for decades. However, at high temperatures, HCl does not produce acceptable results because of its fast reaction, acid penetration, and hence surface dissolution, and its high corrosion rate. As a result, alternatives to HCl have been investigated including organic acids. In this work, the reaction of a new organic acid with calcite was investigated using the rotating disk apparatus and coreflood setup. The organic acid was obtained using both a phosphorous-based and iron-based catalyst.

The rate of reaction of a 10 wt% solution of the new organic acid was measured using the rotating disk apparatus at temperatures up to 250°F. Low-permeability Indiana limestone (1-5 md) samples of 1.5 in. diameter and 0.75 in. length were used. The effect of disk rotational speed (100-1,500 rpm) was investigated. Also, three coreflood experiments at an injection rate of 2.0 cm3/min and a temperature of 300°F were performed to study the effect of acid on the wormhole propagation in calcite. Low-permeability Indiana limestone (1-5 md) cores used in these experiments have a diameter of 1.5-in. and a length of 6 in. Samples of the reacted fluid were collected periodically and calcium and iron concentrations were measured using Inductively-Coupled Plasma, and used to determine the acid-rock reaction rate and to study the possibility of precipitation.

For the phosphorus-based acid, experimental results showed that the rate of calcite dissolution at 205°F was controlled only by the rate of mass transfer of the acid to the surface. However, at 250°F, the reaction was controlled by both mass transfer and by the kinetics of the surface reaction. At 205°F, the reaction rate varied from 7.79E-07 to 4.47E-06 gmol/cm2.s, while at 250°F, the range was between 5.82E-07 and 2.72E-06 gmol/cm2.s. In coreflood experiments, the phosphorus-based acid caused phosphorous precipitation at 300°F, while the iron-based acid achieved breakthrough. This paper summarizes the results obtained and recommends the use of the new organic acid for field applications in calcite reservoirs.
Use of Tracers To Evaluate and Optimize Scale Squeeze Treatment Design in the Norne Field
Authors: Vazquez O. , Mackay E. , Tjomsland T. , Nygard O. , Storas E.
Published: June 2014

When squeezing scale inhibitors into oil production wells the inhibitor should usually be uniformly placed in the open intervals to optimise squeeze lifetime. In wells with varying reservoir quality and/or significant cross flow, however, uniform placement is difficult to obtain. Flow diverters are frequently used to improve the chemical placement. In many cases it is of great interest to evaluate the squeeze performance and assess the actual placement and back production of inhibitor to gather well information and thereby be able to optimise the future squeeze designs. This can be particularly interesting in subsea wells where other kinds of data collection, such as production logging, is not feasible due to high intervention costs and high operational risk. This study suggests the use of tracers during squeeze treatments to evaluate the placement as an alternative to running PLT.

The main purpose of this paper is to demonstrate the applicability of tracers, in this particular study the injection of a KCl slug in a producer well in the Norne Field, to evaluate the layer flow rate profile along the completion interval, which depends on each layer's pressure and geological properties. The study consists first of verifying the layer flow rate profile predicted by a history matched reservoir model. Then based on this layer flow rate profile, a tracer injection programme was designed, which included two production stages at different rates. Finally, based on the reservoir model predictions it is identified that each layer is at different pressures, and this leads to a distinctive return profile.

To evaluate the match between the observed and the simulation data, the layer flow rate profile from the reservoir model was used to populate a specialized near wellbore model for scale squeeze treatments. The match between the simulated and the observed data was good. However, the near wellbore model, in particular the layer flow rate profile, was further fine tuned. Finally, the fine tuned near wellbore model was used to optimize future treatments more accurately with the fine tuned layer flow rate profile.
Laboratory Characterization of Gel Filter Cake and Development of Nonoxidizing Gel Breakers for Zirconium-Crosslinked Fracturing Fluids
Authors: Reddy B. R.
Published: June 2014

Borate or Group 4 metal-crosslinked biopolymer fluids constitute the bulk of gelled-fracturing-fluid volumes used in field-fracture stimulation operations to date. Oxidizing chemicals remain the primary gel breakers to break down the filter cake and establish regained formation permeability or fracture conductivity. These breakers presumably oxidize the polymer backbone, causing chain breakdown and facilitating fluid flowback. Safety hazards associated with the use of bulk quantities are one of the many potential problems associated with the use of oxidizing agents as gel breakers. Proper timing of gel breakdown is of utmost importance with respect to oxidizing gel breakers. Conversely, premature polymer oxidation can cause premature proppant settling. On the other hand, a long delay between the completion of the fracturing operation and activation of the gel breaker could cause the deposition of additional filter cake on fracture faces, which could be difficult to break down. A desirable advancement of designing improved fracturing fluids is to develop nonoxidizing gel breakers that focus on decrosslinking the crosslinked gel structure by reacting with the crosslinking agent, rather than only breaking down the polymer chain. In addition, by insolubilizing such breakers, they can be embedded in the filter cake and, when activated, they can degrade the filter cake completely without leaving any residues.

In this paper, synthetic disks of different porosities were used to simulate formation-permeability damage caused by filter cakes formed by Zr-crosslinked, carboxylated guar-based gels, and the results were compared with those measured for uncrosslinked fluids. The filter cakes were formed under different applied-pressure regimes and characterized for their polymer content and filter-cake/filtrate-weight ratios. From flow-rate measurements, it was clear that uncrosslinked base polymer solutions did not cause any permeability damage. Uncrosslinked polymer fluids produced from Zr-crosslinked gels by use of decomplexing, nonoxidizer breakers also did not significantly damage disk permeability compared with the fluids produced from conventional, oxidizer-type breakers. Several ortho-disubstituted aromatic compounds containing polar heteroatoms capable of functioning as potentially strong ligands for zirconium were found to be suitable as decomplexing breakers. Biopolymers containing such functional groups, notably lignosulfonate derivatives, show promise as commercially viable alternatives to oxidizing breakers for metal-crosslinked fracturing fluids.
Activator Development for Controlling Degradation Rates of Polymeric Degradable Diverting Agents
Authors: Reddy B. R. , Cortez Janette
Published: June 2014

Hydrolytically degradable polymers (generally aliphatic polyesters) have been used in a variety of applications in the oil field, such as fluid diversion, fluid-loss control, and filter cake removal applications. In general, diverting agents and fluid- loss-control materials are only necessary to perform the intended function for a finite amount of time. Once the well is completed or placed on production, it is desirable that the degradable materials be removed so that they no longer have any influence on subsequent fluid flow. With time and temperature, the degradable polymers will break down by forming water- soluble byproducts, leaving behind limited, if any, residual formation damage. The effective formation sealing by these materials while in place, and eventually during cleanup, has made them sought after for a growing number of applications. However, for cooler temperatures, and applications where the well must be placed on production more quickly, there have not been many options to controllably increase the rates of polymer degradation. This has considerably limited the realization of the full potential of the technology. There is an increasing demand for faster cleanup of the diverting agents and fluid-loss- control agents for applications at cooler temperatures.

Strong acids and bases are known to accelerate the degradation of these polymers. Use of such materials can present several disadvantages, such as corrosion and/or undesirable reactions with the formation. Although enzymes are used for the activation of ester hydrolysis, the use of enzymes has not demonstrated effectiveness in all situations. There is a need for chemical activators that can controllably accelerate the degradation of polymers at wellbore temperatures without the detrimental effects of using strong acids or bases. This paper discusses specific activators that can degrade various types of polymers and polymer blends containing degradable functional groups in the polymer backbone. The polymers tested in this study had variable crystallinities and chemical compositions. This paper also presents a new approach to degradation activation that should be more desirable in oilfield applications where the degradation times can be controlled for wide range of temperatures and wellbore conditions.
Experimental Investigation and Correlation of Thermal Effects on Near-Wellbore Formation Treatment by Gel Particles
Authors: Al-Ibad Adnan , Civan Faruk
Published: June 2014

The plugging and permeability impairment processes involved in the treatment and conditioning of high permeability porous formations is investigated at various temperatures by flowing of a suspension of gel particles through unconsolidated proppant packs. The permeability reduction and resistance factor are inferred by measurements of the pressure differentials with time across the proppant pack. Temperature effect is observed to be an important factor in suspended gel treatment of high permeability near-wellbore zones because temperature affects the gel properties and placement rate processes significantly. The effective mechanisms of the consecutive plugging and unplugging processes occurring during the flow of gel particles suspension through the proppant pack are identified and the best-estimate values of their rate coefficients are determined. The laboratory measurements of the viscosity, differential pressure, permeability reduction, and resistance factor are correlated successfully as functions of temperature. Various empirical correlations of practical importance developed in this work can be used for effective design of the suspended gel particles treatment in weak and highly permeable near-wellbore formations. These correlations can predict the effect of temperature on conditioning of the high permeability and weak formations by injection of suspension of gel particles.
Evaluation of Environmentally Acceptable Surfactants for Application as Flowback Aids
Authors: Galindo Tanhee , Rimassa Shawn
Published: June 2014

Recovery of injected fluids from aqueous hydraulic fracturing applications can be enhanced by the use of flowback aids. These additives are typically surfactants or co-solvents that reduce capillary pressure and water blocks. A range of different types of flowback aids, which contain water-wetting nonionic to amphoteric and oil-wetting components, are commercially available for use in hydraulic fracturing applications.

This paper evaluates various environmentally acceptable non-ionic and anionic surfactants for application as flowback aids in hydraulic fracturing applications. Fluid recovery was increased significantly with different alkyl polyglucosides and alkyl ethoxylates. Fluid recovery could be improved from 10% with base fluid up to 89% with the addition of a surfactant. Performance in fluid recovery corresponds best with surface tension data and capillary pressure reduction data, calculated from the surface tension and contact angle. Contact angle measurements alone cannot be used as screening tools for flowback aid evaluation.

Heightened concerns about the environmental impact of chemical additives used in fracturing fluids along with new and pending environmental requirements have led to a demand for chemistries with reduced environmental impact. Products tested meet or exceed U.S. Federal or state environmental chemical compliance guidelines.
Improving Oil Recovery In Gas-flooded, Oil-wet Carbonate Reservoirs by Wettability Altering Surfactants
Authors: Wang Leizheng , Mohanty Kishore K.
Published: June 2014

Carbonate reservoirs have complex pore structure and tend to be oil-wet. The remaining oil saturation is often high after a gas flood. The goal of this work is to develop and evaluate surfactant formulations that can improve the oil recovery after a gas flood. An anionic surfactant was used to develop a low IFT and wettability altering formulation for a soft injection brine and EDTA was added to modify the formulation for a hard injection brine. These surfactant solutions changed the wettability of an oil-wet calcite plate to intermediate-wet/water-wet conditions. Core spontaneous imbibition tests and corefloods were conducted. These displacements were simulated using CMG-STAR to study in-situ viscous fingering during gas injection and improved oil recovery using surfactant formulations. The hard brine surfactant formulation recovered 54% of the original oil in 60 hours by spontaneous imbibitions compared to 12% for the soft brine surfactant formulation and no oil for the formation brine. Initial gas flood left a lot of oil unswept. EDTA assisted hard brine surfactant formulation could recover over 40% of the oil, higher than 25% for the soft brine surfactant formulation. The gas injection after the surfactant slug increased the pressure drop due to foam formation. Numerical simulation of the GSG flood showed in-situ viscous fingering during the first gas injection and efficient oil displacement during the surfactant injection and the subsequent gas injection.
A New Finding in the Interaction Between Chelating Agents and Carbonate Rocks During Matrix Acidizing Treatments
Authors: Assem A. I. , Nasr-El-Din H. A. , De Wolf C. A.
Published: June 2014

During matrix acidizing, successful iron control can be critical to the success of the treatment. Iron (III) precipitation occurs when acids are spent and the pH rises above 1, which can cause severe formation damage. Chelating agents are used during these treatments to minimize iron precipitation.

In this paper, we studied the effect of iron precipitation in acidizing operations. HCl solutions (5 - 20 wt%) containing 5,000 to 10,000 ppm of Fe3+ were used in these experiments. Biodegradable GLDA (glutamic-N, N-diacetic acid) was studied in the experiments. The effect of varying acid concentration and chelate-to-iron mole ratio was examined. Coreflood experiments were conducted on low permeability Indiana limestone (1 - 5 md) at 200°F. The cores were scanned after treatments using a CT scanner. The core effluent samples were analyzed for total iron and calcium concentrations using ICP-ES. A calcium ion-selective electrode was used to determine the concentration of free calcium ions, i.e. calcium ions not complexed by the chelate, in the core effluent samples.

Results showed that the amount of iron recovered depended on both chelate-to-iron mole ratio and the initial permeability of the cores. Calcium is chelated along with iron, which limits the effectiveness of chelating agents to control iron (III) precipitation. Chelating agents are supposed to control iron now that calcium is also chelated, this amount should be accounted for. Acid solutions should be designed considering this important finding for more successful treatments. This paper will discuss the results obtained and give recommendations to enhance the effectiveness of these chemicals in the field.