bluuebunny/crossref_metadata_2025 huggingface dataset:
Time-Resolved Fluorescence for Real-Time Monitoring of Both Scale and Corrosion Inhibitors: A Game-Changing Technique
Authors: Marais A. , Martini M. , Lepoivre F. , Ould-Metidji M. , Collet A. , Tillement O. , Hurtevent C. , Baraka-Lokmane S.
Published: April 2016

Inhibitor products have been widely used to reduce both steel corrosion and scale deposition on pipelines, tubings and safety valves in critical offshore sites. Their simultaneous injection with brine has gradually increased the lifetime of production wells with incontestable benefits for the oil and gas industry. However, the large use of such additives has not been followed by the development of any efficient technique of dosage that considers the strict requirements of an offshore platform.

In this paper, we describe a novel method of chemical dosage that takes into account all the on-site technical and practical parameters, such as the quantification thresholds or molecule specificity, the real-time monitoring, the resistance and compactness of measurement device and a user-friendly interface of measurement. Current techniques of inhibitor monitoring that use elemental analysis (ICP, MS, …) for sub-ppm quantifications appear too complex for a successful long-term on-site industrial exploitation due to the bulky dimensions of apparatus and the delay and complexity of analysis.

A long-term collaboration between University of Lyon and Total EP has defined a simple and accurate method for inhibitor monitoring based on the use of lanthanide tracers and the Time-Resolved Fluorescence (TRF) technique. We exploited the fact that inhibitor chemicals (i) are good chelators for lanthanide ions and (ii) amplify the luminescence signal of rare-earths. In this way we are able to collect the photon emission signal by TRF apparatus and dosing the inhibitors. The portability of the TRF device as well as the sensitivity of detection have been engineered in order to obtain a sub-ppm quantification threshold via 1-click task. Several carboxylates, phosphonates and sulphonates additives diluted in brine solutions has been easily measured out even in presence of residual oil. More than 20 commercial inhibitor solution samples were quickly prepared and dosed with an impressive linearity of response (R2 test > 0.996) in the 10 – 100 ppm range. Any further extension of range has been possible. In addition, we were able to quantify two inhibitors (scale – scale, scale – corrosion) in the same brine water. This technique certainly opens a new conception of smart chemicals management in oil and gas production for (i) a dramatic minimization of the injected compounds (ii) a reducing delay in pipelines monitoring, and (iii) a shut down of expenses of pipeline maintenance.
Dissolution of Sulfide Scale: A Step Change With a Novel, High Performance, Non-Mineral Acid Chemical
Authors: Wylde Jonathan J. , Okocha Cyril , Smith Rashod , Mahmoudkhani Amir , Kelly Craig J.
Published: April 2016

Iron sulfide scale can be relatively common-place in maturing oil wells and produced water handling systems. Iron sulfide can also be commonly formed as a corrosion product, due to sour corrosion resulting from H2S containing fluids being processed through carbon steel tubulars. As more sour production is brought on-stream iron sulfide continues to become more prevalent. There are few options for removing deposits of iron sulfide scales especially when it comes to choice of chemistry. This paper discusses the most commonly performed techniques for iron sulfide removal, including hydrochloric acid, organic acids and THPS, and the varying degrees of success that these chemistries have in application. Challenges using hydrochloric acid are encountered due to the potentially high yield of H2S upon dissolution of the scale, along with FeCl2 and therefore the potential of secondary deposition.

This paper provides data on the development of a new dissolver for iron sulfide. Dissolver tests were performed initially on laboratory generated iron sulfide scale to optimize the formulation. Further testing was performed on different polymorphs of iron sulfide including pyrite, pyrrhotite, troilite, marcasite and mackinawite. Furthermore, several field scales were obtained and after XRD analysis, tested with the novel dissolver chemistry. It was shown that the new chemistry significantly outperformed THPS based dissolvers (active for active) and as well as 7.5% HCl. The corrosion rate of the novel chemistry was significantly lower than inhibited HCl and commercial THPS based blends. Testing was also performed at high pressure in order to understand the influence that pressure has on dissolution rates for all the commonly used dissolver chemicals. The new dissolver chemistry has significant chelating ability for sulfide scales as well as other ‘standard’ scale types including, calcium carbonate and calcium sulfate. The new product offers an effective multi-functional solution to dissolution of heterogeneous scale deposits.

The paper concludes with a case history of field application summarizing in detail the parameters of the field deployment and various KPIs used to measure success. The application is unusual as it was performed using a continuous injection method into an online system.
Development of Improved Chemical Formulations for Scale Control for Alkaline Surfactant Polymer Flood in a Seawater Flooded Reservoir
Authors: Bt Alwi Noraliza , Bt Salleh Intan Khalida , Ibrahim Jamal Mohamad , Carpenter Ian , Dyer Sarah J. , Simpson Caroline , Frigo Dario M. , Graham Gordon M.
Published: April 2016

Calcium carbonate scale control during Alkaline Surfactant Polymer (ASP) flooding is a recognised challenge due to mixing of the high-pH ASP waters with reservoir brine. In most cases ASP flooding is aimed towards reservoirs containing low-calcium and magnesium formation waters, and previous reports have concluded that in such cases production well scaling can be effectively treated with conventional scale inhibitors. For reservoirs containing moderate to high levels of alkaline-earth metal ions in the produced waters, such as reservoirs that have been flooded with sea water, the scaling risk is considerably exacerbated, with the result that conventional scale inhibitors are essentially ineffective except at very low sea-water fractions in the produced water mixture following ASP breakthrough.

This paper presents the results for an extensive research and development project firstly to examine alternative inhibitor chemistries and then to develop more complex formulations containing synergistic additives to improve calcium carbonate scale control in high sea-water content produced waters in ASP floods. The developed formulations are shown to control the scales effectively with water chemistries that were previously shown to be beyond the efficacy of conventional inhibitors (negligible effect at 500 mg/l).

The paper will present and discuss the different types of scale inhibitor chemistries examined, the nature of other chemistries and additives examined in combination with the scale inhibitors, and will describe the synergistic effects observed between the different chemicals.

Results from this extensive series of laboratory tests will then be presented showing the considerable benefits of the new formulations and demonstrating how scale inhibition can now be achieved under these extreme and previously uncontrollable producer well conditions. The paper will also introduce the challenges and present an overview of the case study that initiated this development program.
Predicting Calcite Scaling Risk Due to Dissolution and Re-Precipitation in Carbonate Reservoirs During CO2 Injection
Authors: Ribeiro Ayrton S. , Mackay Eric J. , Guimarães Leonardo
Published: April 2016

Carbonate reservoirs are more geochemically reactive than sandstones and can experience big changes in porosity and permeability because of mineral reactions. In this work, we analysed the calcite dissolution and precipitation in chalk reservoirs during injection of seawater and CO2 bearing fluids.

We performed reactive transport simulations with injection of seawater, carbonated water, CO2 gas, CO2 SWAG and CO2 WAG. We evaluated the mineral reactions that occur in the injector and producer blocks. Moreover, the calcite dissolution rate was calculated and its relationship with flow rate was investigated.

Simulation results showed that during injection of CO2 gas alone, calcite dissolution was fast but limited, and occurred everywhere. On the other hand, for the other injected fluids the dissolution around the injector was continuous and, with the exception of the seawater scenario, precipitation was observed downstream. In addition, the calcite dissolution per injected water pore volumes for both CO2 SWAG and CO2 WAG was higher because of higher dissolution of gaseous CO2 in injected and formation waters. Moreover, the dissolution rate was found to be proportional to the water flow rate which confirms the assumption that calcite kinetics are fast compared to reservoir flow.

This knowledge is valuable when planning CO2 WAG projects in carbonate reservoirs. As dissolution rates increase with flow rates, high permeability zones will show faster porosity changes, which may compromise the injector wellbore integrity and may lead to a more severe and growing calcite scaling risk around the producer wellbore.
Modelling Squeeze Treatments in Fractured Systems - A Case History
Authors: Kaur Amarpreet , Spooner Victoria E. , Frigo Dario M. , Stalker Robert , Graham Gordon M. , Jordan Myles M.
Published: April 2016

Scale inhibitor squeeze treatments in high-permeability sandstone reservoirs can be readily simulated using matrix flow models. However, designing such treatments for application in fractured shale reservoirs is less developed, partly because the mechanisms for fluid flow are less well understood and partly because the manner by which the inhibitors are transported and retained in fractured shale formations differ considerably from the simple matrix flow encountered in sandstone reservoirs.

Accurate prediction of squeeze treatment lifetimes is important for scale management both economically, to ensure optimum productivity at lowest cost of operation, and practically, to schedule treatments appropriately. Until recently this has not been achievable for fractured shale formations without the use of full-field simulators. This paper demonstrates that even a near-wellbore model, if appropriately modified, can achieve good agreement with inhibitor-returns field data from bullheaded squeeze treatments in 7 different multiply fractured wells in 2 different Unconventional shale formations.

Field data were compared with simulations using a model that couples inhibitor diffusion into and out of the rock matrix with adsorption either onto the rock matrix or the fracture proppant or both; it was found that in some field cases there is negligible difference between inclusion or exclusion of proppant adsorption, whereas in others much better simulation of inhibitor returns is observed if proppant adsorption is included.

Other aspects have been included in the model, such as the influence of proppant embedment (changing the porosity of the fracture void) and treatment of only a fraction of the multiple fractures present in a well. Interestingly, inhibitor returns in the 3 wells in one field correlated best with simulations assuming only a low fraction (up to 30%) of fractures were treated by the squeeze, whereas simulations from 4 wells in another field correlated better with a much higher fraction of fractures (60 – 90%) being treated.

This paper illustrates that an appropriate near-wellbore model can give good agreement with field data provided plausible physical phenomena are included, and that such a model can be used to design better squeeze treatments in Unconventional fractured-shale reservoirs without the need for complex full-field simulators.
Impact of Reservoir Temperature on Scale Inhibitor Retention - The Challenge of Ultra-Low Temperature Sandstone Reservoirs
Authors: Jordan M. M. , Johnston C. J , Sutherland L.
Published: April 2016

Control of inorganic scale within oilfield production wells via the scale squeeze process is well documented. The life time of the squeeze treatment is dictated by the cumulative volume of produced water flowing through the treated interval until the minimum inhibitor concentration (MIC) of the scale inhibitor is reached. Inhibitor chemicals with strong retention and low MIC values have been developed, deployed and for many years phosphonates and polymers containing phosphonate functional groups have been widely used.

This study looks at the issues faced by an operator with a low temperature sandstone reservoir of only 40°C and the challenges this low temperature brought which include high MIC for sulphate scale control and poor chemical retention & release observed during the reservoir condition corefloods. These findings will be compared and contrasted with two other higher temperature (71°C and 95°C) sandstone reservoirs where phosphonates and phosphate ester chemicals have been evaluated and deployed in the field.

The findings from this detailed coreflood study and review of previous experimental/field deployed scale squeeze treatment data shows that phosphonates work very well at elevated temperatures at and above 70°C where their stronger retention and excellent release profiles makes them a favoured chemical for such treatments, however at lower temperatures these molecules are not well retained on the rock and it is the phosphate ester chemicals that are more effective and provided the longer squeeze life. Comments on the interaction/performance of polymer scale inhibitors will also be made for these low temperature conditions

The implication of these findings clearly show that phosphate esters offer the potential for extended squeeze lifetime in the <50°C sandstone reservoirs which are being developed in Northern Norway (Barents Sea) and the shallow depth, cool reservoirs being developed in offshore Brazil.
Using a Real-Time Visualisation Technique for the Assessment of Surface Scale Kinetics and Mechanisms of Inhibition
Authors: Sanni Olujide , Bukuaghangin Ogbemi , Charpentier Thibaut , Kapur Nikil , Neville Anne
Published: April 2016

Improving the understanding of surface scale formation is important in implementing an effective scale management strategy in the oil and gas industry. Investigations into scale formation have largely been focused on precipitation in the bulk solution by assuming that surface scaling always results from pre-precipitated crystals in the bulk solution. However, recent studies have shown that scale inhibition efficiency and the effects on crystal morphology vary between surface and bulk processes

The study is focused on the formation of BaSO4 and CaCO3 scale on stainless steel surface at constant saturation ratio (SR) using a visualization flow rig. The effects of SR, flow rates and temperature on surface scaling were studied. Also, the influence of SR and inhibitor concentration on surface inhibition efficiency of Polyphosphinocarboxylic acid (PPCA) and diethylenetriamine penta methylphosphonic acid (DETPMP) were studied. The range of SR considered is between 10 and 80 and with these values the experiments are conducted with no pre-precipitated crystals in the bulk solution. The flow rates used are between 10ml/min to 60ml/min.

It is shown that the determination of surface crystallization mechanisms and kinetics allows for the correct type and dosage of inhibitor to be selected. Addition of inhibitors at the bulk minimum inhibition concentration (MIC) actually aggravates surface scaling. For a similar range of SR and test conditions, CaCO3 scale builds up on the surface shows the predominance of growth which results in bigger crystals and a smaller number of crystals while BaSO4 scaling results in a higher number of crystals nucleating from the surface asperities with slower growth rate and hence smaller crystals.
Silica and Silicate Scale Formation and Control: Scale Modeling, Lab Testing, Scale Characterization, and Field Observation
Authors: Wang Wei , Wei Wei
Published: April 2016

We report an integrated study on silica and silicate scales in steam generator tube and water injection wells based on scale modeling and testing, scale sample characterization, and field observations.

For the steam generator tube scenario, significant amount of metal silicates in field scale sample were identified, which is consistent with the extremely high scaling potential indicated by scale modeling. Halite formation was not predicted by scale modeling but significant amount of halite was identified in the scale sampled from inside of a generator tube. It is suspected the formation of metal silicates, especially Fe silicates, can facilitate/accelerate the formation of other type of scales and eventually lead to the tube plugging, overheating, and failure.

For the injection well scale management study, silica and silicate were identified in the scale precipitates from waters sampled at upstream of the injection point. While scale modeling (based on the composition of the filtered water samples) indicates potential further metal silicate scale deposition at wellbore temperature and pressure conditions, no significant amount of metal silicate scale was identified in lab testing with current available field water samples. Lab testing shows the dominating scale for injection well is calcite, which appears consistent with learnings from an initial field trial testing.
Scaling of Calcium Carbonate on Heated Surfaces - Crystallization or Particulate Fouling?
Authors: Broby Margrethe , Neteland Marte , Ma Xiaoguang , Andreassen Jens-Petter , Seiersten Marion
Published: April 2016

One of the main challenges with mono ethylene glycol (MEG) loops is to achieve controlled removal of produced salts and at the same time avoid uncontrolled precipitation and scaling on heat exchanger surfaces. Scaling is described in the literature as occurring both by particulate and crystallization fouling which is of particular interest in MEG regeneration processes with heat exchanger surfaces being exposed to solutions with significant quenatities of particles in the liquid bulk. In order to control the process it is essential to understand to which extent scale formation is driven by crystal growth on the surface as compared to particulate fouling of particles originally precipitated in the liquid bulk.

Surface scaling was studied in a laboratory setup where a heated stainless steel tube is inserted in a well-mixed continuously stirred tank reactor allowing for control of the steady state supersaturation and the bulk temperature. To test if particulate fouling is contributing to the scale formation premade particles of a different calcium carbonate polymorph was seeded to the system.

By running the system with pre-scaled tubes of calcite and at the same time seeding with vaterite particles, it was shown that particulate fouling is not an important growth mechanism. For aragonite scales produced on a tube heated at 90 °C, we found that vaterite particles were incorporated to a certain extent into the porous scale structure. However, the simultaneous consumption of supersaturation by the vaterite particles in solution as well as by the scale layer, atually lowered the scale thickness. This reduced scale layer growth was confirmed by heat exchanger data.

We found that particulate fouling is not an important mechanism for build-up of calcium carbonate scales. Presence of bulk particles can even be advantageous by reducing the available supersaturation for surface scaling.
Advances in Understanding Effects of Shear and Turbulence on Scale Formation, Adhesion and Growth on Surfaces
Authors: Nichols David A. , Frigo Dario M. , Graham Gordon M.
Published: April 2016

Inorganic scale formation in oilfield systems is greatly influenced by the fluid-flow regime, with shear rates and turbulence affecting nucleation, surface growth, morphology and adhesion. However, current scaling risk analysis relies upon thermodynamics-based predictions together with simple rules-of-thumb to address kinetics because the impact of flow regime is poorly understood. Similarly, scale inhibitor performance is typically evaluated under static or low-shear, laminar-flow conditions, which are highly unrepresentative of those in most production systems.

This paper examines scale deposition at metal surfaces and bulk-phase precipitation as a function of shear and turbulence, highlighting how rate and even scale composition can change in systems with mildly oversaturated sulphate tendencies. Conventional static and low-shear methods are compared with those using rotating cylinder and jet impingement to achieve high Reynolds numbers and shear stresses up to 400 Pa (and even 10,000 Pa via more sophisticated approaches). This builds upon earlier work (SPE 169761) and demonstrates the influence of fluid-flow dynamics on the critical supersaturation required to induce scaling, and by extension, on the nature of the deposit that may form where a system is mildly oversaturated for more than one scale. An example is where a sulphate scale at lower supersaturation precipitates under high shear conditions preferentially over another sulphate scale with higher supersaturation.

This work also highlights the significance of better matching shear and turbulence in the ranking of scale inhibitors, reporting differences in the relative performance of different generic inhibitors as a function of shear.

Finally, the paper describes the new test methods by which scaling propensity and inhibitor performance can be determined under conditions of shear and turbulence that are more representative of production conditions. A key aspect of this is that it facilitates testing of mildly supersaturated systems without having to adjust brine chemistry, leading to better understanding of the magnitude of uncontrolled scaling and of the Minimum Effective Dose of inhibitors to control it.
Impact of FeIII/FeII on Scale Inhibition
Authors: Zhang Zhang , Liu Ya , Dai Zhaoyi , Bhandari Narayan , Zhang Fangfu , Yan Fei , Ruan Gordon , Alsaiari Hamad , Lu Yi-Tsung , Deng Guannan , Kan Amy , Tomson Mason
Published: April 2016

Little research has been done to understand how chelating agents might reverse the effect of Fe(III)/Fe(II) on scale inhibitors in oilfield conditions. Iron ions are common cations existing in oil and gas production water. Most Fe(II) ions come from dissolution of siderite in reservoir and corrosion of steel pipes. Fe(III) in solution, can be formed by Fe(II) reduction of H2O, dissolution of magnetite or other Fe(III) containing minerals or when produced water is exposed to air. Both Fe(II) and Fe(III) can cause severe problems in production. Fe(II) can form FeS and FeCO3 scale. Fe(III) can precipitate as ferric hydroxide or with Fe(II) as magnitite particles and cause damage to formation permeability. Moreover, both Fe(II) and Fe(III) have significant detrimental effects on common scale inhibitors. One of the most popular methods for iron control is the application of chelating agents, such as EDTA, NTA or citric acid, to chelate Fe(II)/Fe(III)to prevent such detrimental effects.

In this work it is shown that Fe(II) and Fe(III) can significantly impair performance of common scale inhibitors such as DTPMP, PPCA and PVS. The inhibition time of DTPMP for barite can drop more than 90% in the presence of 1 mg/L Fe(II) or Fe(III)at 70°C. In this research, a mechanistic study has been done to deduce whether EDTA and citric acid can reverse the loss of scale inhibitor performance by Fe(II)/Fe(III). We find that Fe(III) impairs scale inhibitor performance by forming iron hydroxide particles which can adsorb scale inhibitors from solution. Both EDTA and citric acid are found to be able to eliminate the negative impact of Fe(III) on scale inhibitors, but through different mechanisms. EDTA works by direct chelation of Fe(III) in solution, before a solid phase is formed; while citric acid works by competitive adsorption with scale inhibitor onto ferric hydroxide particle surfaces. The impact of EDTA and citrate on reversing Fe(II) effect on scale inhibition is also discussed.
High Pb and Zn Concentrations in Formation Water from the Culzean Field: Real or Artefact?
Authors: McCartney R. A. , Brice S. , Chalmers A.
Published: April 2016

Formation water compositions are an important input to scale management planning on new fields. The quality of these data can be verified by evaluating formation water sampling and analysis conditions and also by comparing the analyses with analogue data from similar fields. But, this can be problematic when the analyses of interest are not commonly obtained. In this paper we present such an example.

The HTHP Culzean Field is located in Block 22/25a, East Central Graben, UK North Sea. Although an initial evaluation of formation water samples/analyses obtained from the Skagerrak Formation indicated that their quality was reasonably good, the formation water contained 172±9 ppm Pb and 452±24 ppm Zn. These concentrations are high when compared with the few published/unpublished analyses for North Sea formation waters; at these concentrations there is a potential Pb-Zn sulphide scale risk at Culzean.

To confirm the Pb and Zn analyses, they were compared with a wider variety of analogue data from a range of crustal fluids (including other global oilfield formation waters, and shield, geothermal, metamorphic, hydrothermal, and magmatic waters). This showed that the Culzean formation water has a Pb/Zn ratio characteristic of crustal fluids and the high concentrations appear to be the result of (a) a geological source of Pb and Zn, (b) high salinity, low pH and low total reduced sulphur content of the Culzean formation water and (c) high reservoir temperature. It was concluded that high Pb and Zn concentrations of the Culzean formation water are likely to be representative of those naturally-occurring in the reservoir and are not an artefact of drilling, sampling or analysis.

This study has shown that analogue data from a variety of crustal fluids can be used to establish the quality of oilfield formation water analyses. This is particularly useful when the constituents of interest are not commonly detected or determined in oilfield formation waters. This has helped confirm the potential sulphide scale risk at Culzean and explains the reasons for elevated Pb and Zn in formation waters from other fields in the East Central Graben of the North Sea.
Accurate Detection of Tagged Polymeric Scale Inhibitors in Oilfield Produced Water Samples
Authors: Vuori Vesa , Nuutinen Vesa , Honkanen Tapio , Griffin Rick , Johnstone James , Peltokoski Brita , Lehtonen Annika , Suominen Hanna , Toivonen Susanna
Published: April 2016

Accurate detection of scale inhibitor residuals from produced waters is a critical part of flow assurance. Tagged scale inhibitors have been developed to improve the detection limit. The purpose of having multiple different tags on the same inhibitor chemistry is to be able to separately detect the level of inhibitor for several subsea templates when commingled in a single flow back line to a production facility. These new tagged scale inhibitors combine the excellent scale inhibition performance of sulphonated copolymers with fluorescence technology, delivering lower detection limits of residual inhibitor concentrations.

The authors have developed a testing protocol that enables accurate detection of two tagged scale inhibitors from a produced water sample using fluorescence spectroscopy. The development of the chemistry and detection monitoring technique, and the results demonstrating the validity of the analysis method are discussed. The method has been validated and tested with real produced water samples collected from a subsea field in the North Sea. The samples were spiked with unknown concentrations of two fluorescent tagged sulphonated copolymers with concentrations between 0 and 200 ppm as product.

The tested products have specific excitation and emission wavelengths, enabling the independent detection of both products with a fluorometer without any disturbing effect. The test results clearly show that the protocol can be used for analyzing low concentrations of scale inhibitor polymers from produced waters. The final goal is to analyse residual inhibitor concentrations using a portable fluorometer delivering onsite detection, and thus enabling real-time monitoring of the scale inhibitor squeeze returns.

This fluorescence technology can be used in combination with a phosphorus tagged scale inhibitor and ICP analysis method to detect three products from the same commingled sample. The validity of the protocol has been confirmed and has generated great interest in the oil and gas industry where accurate detection will maximize safe and economic oil production.
Introducing Novel Chemistry for Scale Inhibitor Squeeze Treatments on the Heidrun Field - Challenges Faced and Lessons Learned
Authors: Williams E. , Archibald M. , Selle O. M. , Brandal Ø. , Carter J. , Singaravel V. , Henriksen O. , Gustavsen Ø. , Andresen A. M.
Published: April 2016

Heidrun is recognised as a challenging field for scale management due to the combination of water injection, high barium and clay content, and unconsolidated sandstone formations. A selection and qualification process for scale inhibitor squeeze in this field followed the standard laboratory testing protocols. A novel scale inhibitor chemistry was qualified and field trialled; however, introducing the new scale inhibitor chemistry to the field was more challenging than anticipated.

The technical qualification was successful but the field trial resulted in lost productivity, halting field-wide implementation. The field trial started in Well I and indicated good scale protection but gave considerable loss of productivity. This paper presents the lessons learned through an extensive laboratory investigation to identify specific factors influencing the issues observed with the field trial. Furthermore, work completed to qualify a solution for iron-rich formations is described.

It was determined that the inhibitor was leaching iron from minerals in the reservoir and forming an insoluble complex with the metal, particularly at mildly acidic pH. While elevated iron concentrations were seen in flow-back samples from other wells across the field, these did not approach the levels observed for Well I which was producing from a geological formation rich in iron-bearing minerals. The field trial was successful in less iron-rich formations and the product was implemented field-wide for such reservoir zones. The scale inhibitor was designed to offer strong chelation, a property suited to scale inhibition and reservoir retention, but this was also a significant factor in the productivity loss. This important finding dictated that Product A should be regarded as unsuitable for reservoir zones containing iron-rich minerals. Subsequently, an alternative scale inhibitor was technically qualified and has since been successfully field trialled and implemented in the iron-rich formation.

This selection exercise for Heidrun posed challenges in terms of reservoir retention and iron compatibility for field-wide implementation of new chemistry. Overcoming these issues gave valuable insights for future qualifications of the novel scale inhibitor chemistry.
A Comparison Study on Huff-n-Puff Gas Injection and Chemical Relative Permeability Modification to Mitigate Condensate Blocking in Fractured Shale Gas Condensate Reservoirs
Authors: Sheng Jie , Sheng James J. , Li Lei
Published: April 2016

In the literature, both huff-n-puff gas injection and chemical injection to modify relative permeabilities have been proposed to mitigate condensate blocking near the wellbore; and huff-n-puff gas injection has been proposed to improve liquid oil production in shale gas condensate reservoirs. This paper focuses on the potential of chemical relative permeability modification (RPM) to enhance hydrocarbon recovery in fractured shale gas condensate reservoirs using the simulation approach; and the potentials to improve hydrocarbon recovery by these two approaches are compared.

The relative permeability model is studied and the dependence of gas/oil relative permeability curves on capillary number and interfacial tension is discussed. Chemical treatments to mitigate condensate and water blocking have been successfully implemented in the laboratory with sandstone and carbonate. Accordingly, a brief screening of RPM chemicals is conducted and the mechanism of potential surfactant molecules that may work in shale gas condensate reservoirs are investigated. In this study, a shale gas condensate reservoir model is set up and the reservoir is assumed to be treated with a hypothetic surfactant that improves both the relative oil and gas permeability within the near-wellbore area. The simulation results are juxtaposed with those of huff-n-puff gas injection production.

It is assumed that the surfactant alters the end-point gas/oil relative permeability, residual oil saturation, gas connate saturation, etc. and is durable during the production years. In the surfactant treatment cases, an increase of oil recovery by 1%-3% is observed compared with the primary depletion. However, the optimized huff-n-puff process can achieve up to 8% more oil recovery than primary depletion. In terms of gas recovery, the surfactant treatment process increases gas recovery by 1-2%, while the optimized huff-puff gas injection leads to over 20% gas recovery reduction because of less total production time. To sum up, the huff-n-puff gas injection process achieve more liquid recovery but less gas recovery than the surfactant treatment process. Analysis of simulation data about the changes in drawdown pressure and liquid saturation are proposed. A simple economic analysis is conducted as well. It is concluded that the huff-n-puff process is preferred to the RPM process when the oil price is relatively high due to higher drawdown pressure and the oil saturation reduction near the wellbore by evaporation.

The potential of RPM application in unconventional reservoirs has not been well investigated in the previous literature. This paper is to discuss this potential and to compare the advantages and disadvantages of the surfactant RPM process with those of huff-n-puff gas injection in shale gas condensate.
An Experimental Investigation of Desorption Kinetics and Mass Transfer in Shale
Authors: Wang Yu , Dasani Devang , Tsotsis Theodore T. , Jessen Kristian
Published: April 2016

Methane (CH4) is the largest component of the natural gas produced from shale rocks. Although methane accounts for 87-96 mol% of the gas from these rocks, other components including hydrocarbons such as ethane (C2H6) and propane (C3H8), nitrogen (N2) and helium (He) are also found in the gas produced. Methane and the various heavier hydrocarbons are stored in an adsorbed state in the micro and mesopores of the shale rocks, and as free gas in the fracture networks. Though convective and diffusive transport accounts for the short-term behavior in gas production, desorption is thought to dominate the long-term dynamics of shale-gas generation. The key objective of this study is the investigation of adsorption/desorption and diffusive transport phenomena of methane/hydrocarbon mixtures in shale-gas rocks.

We focus our attention on the pure components of methane and ethane and their binary mixtures, since ethane is typically the second largest component in shale gas, and is thought to compete for the same adsorption sites in shale-gas rocks as methane. We study the adsorption/desorption behavior of this mixture (and its individual components) in ground shale rock samples using thermogravimetric analysis (TGA). The sorption isotherms generated are important to predict the gas storage capacity of the shale samples, while the study of adsorption/desorption dynamics/kinetics help us understand the role of desorption during the later times of gas production. A dynamic Langmuir-type sorption model is proposed, that allows us to isolate desorption kinetics from diffusive mass transfer. This, in turn, facilitates our modeling and interpretation of the experimental observations.

The experimental observations and their interpretation pave a path to improve the interpretation of production data from shale-gas wells by leveraging an improved understanding of desorption dynamics and mass transfer of natural gas mixtures in shale.
A Petrophysical Dual Porosity Model for Evaluation of Secondary Mineralization and Tortuosity in Naturally Fractured Reservoirs
Authors: Piedrahita Jaime , Aguilera Roberto
Published: April 2016

Quantification of secondary mineralization or cementation within natural fractures has not been considered in previous petrophysical dual porosity models. This is however of paramount importance as morphology of the fractures indicates that they can be open, partially or completely mineralized.

If cementation with secondary minerals is complete the recovery of hydrocarbons will be generally very small. If secondary mineralization is partial, production rates and recoveries could be quite significant as the secondary minerals would play the role of natural proppant agents helping to maintain the fractures open as the reservoir is depleted. If the fractures are initially open, production rates and recoveries could be large or small dependent on the orientation of the natural fractures and in-situ stresses.

These observations lead to the key objective of this paper: to develop an analytical dual porosity model for quantifying secondary mineralization (cementation) and tortuosity in natural fractures. The method further allows estimating matrix and fracture porosities, and fracture compressibility based on the amount of secondary mineralization.

Use of the new dual porosity model is explained with two core data sets drawn from tight gas formations in the United States and Canada. A comparison is made with results of current dual porosity models that do not take into account secondary mineralization within the natural fractures and tortuosity.

The conclusion is reached that the proposed dual porosity model provides a valuable new quantitative tool for petrophysical evaluation of naturally fractured reservoirs. In addition, the methodology allows estimating fracture compressibility, a usually elusive parameter needed for estimating original petroleum in place in naturally fractured reservoirs. Although the methodology is explained using data from tight sandstones it also has application in other types of reservoirs and lithologies.
Infill Drilling Opportunity in Fruitland Coal, San Juan Basin, Colorado
Authors: Parihar Prannay , Warner Russell , Micikas James , Armpriester Lianne , Anderson James , Zuluaga Elizabeth
Published: April 2016

The San Juan Basin, located in northwestern New Mexico and southwestern Colorado, is one of the most prolific natural gas producing regions, and one of the largest gas basin in the United States in terms of total estimated gas reserves. More coalbed methane has been produced from the San Juan Basin than the rest of the world combined. This paper analyzes the performance of original and infill wells producing from the Fruitland Coal formation and offsetting Chevron's acreage position in key areas of the North San Juan Basin. Subsurface and production data of these wells available in the public domain formed the basis for the project team to recommend an infill drilling program to maximize the value of the company's current acreage position.

The project team developed a comprehensive approach to arrive at a probabilistic production forecast and utilized subsurface data on coal gas content and bulk density available in public domain for San Juan Basin to confirm the remaining gas-in-place and need for additional takeaway points in the reservoir. Decline curve analysis was used to assess the production performance of more than one hundred infill wells drilled since 2007 and to determine the potential impact on the expected ultimate gas recovery of the offset original 160-acre spacing wells. Understanding potential interference risk was critical to justifying the need for downspacing.

The project team recommended drilling additional infill wells based on several criteria: no observation of significant interference with the majority of existing producers, considerable remaining gas-in-place that could not be developed at the current well spacing and a positive correlation between performance of Fruitland Coal wells and the thermal maturity of the San Juan Basin. The project team performed data analysis of four different type producing areas (TPAs) delineated within the basin based upon similar reservoir characteristics and production behavior. The data analysis confirmed the opportunity to drill and reduce spacing for improved recovery in areas where underlying geologic parameters like reservoir connectivity and reduced permeability has led to low recovery.
Experimental Study of Permeability Decline in Tight Formations During Long-Term Depletion
Authors: Cui Q. , Abass H. H.
Published: April 2016

Hydrocarbon production decline behaviors in low permeability reservoirs and conventional reservoirs are significantly different; in such a way that high initial rate is usually observed for a short period in tight formation wells, then the well productivity drops dramatically. The rapid production decline in shale wells has a strong relationship with the loss of rock matrix permeability and reservoir conductivity, resulting from the dissipation of pore pressure during reservoir depletion. This paper presents experimental studies of stress-dependent compaction in tight reservoirs and its impact on long-term recovery.

The magnitude of rock permeability change depends on the in-situ effective stress, which is a combined effect of reservoir pore pressure and confining stress. In this research, permeabilities of a series of shale and sandstone core plugs are measured in the laboratory using pressure transimission test technique. The samples are tested under multiple confining stress and pore pressure combinations. Several confining stress are pre-set to represent different reservoir stress conditions. Different pore pressures are then applied to mimic reservoir depletion process under specific confining stress conditions. The permeability is calculated for all scenarios and pressure dependent permeability behaviors are analyzed for each type of sample.

The interpretations of effective stress dependent permeability show that different types of rocks have different permeability decline signatures responding to the depletion effect. In addition, tight rocks with different dominant porous media (i.e., matrix and fractures) are found to have different permeability behaviors. Characteristics of permeability decline at different pore pressure intervals are analyzed and the critical reservoir pressure and depletion index (i.e., ratio of pore pressure to overburden stress) are identified for different types of rocks where significant permeability change occurs. Based on the stress dependent permeability measurements, the Biot Coefficient is also determined for different tight samples.

Recognizing permeability decline signatures of tight reservoirs provides significant insights into long-term dynamic reservoir conductivity monitoring and contributes to the field management practices. It is indicated from the study that the permeability decline in tight reservoir wells can be significant with continuous depletion while maintaining reservoir pressure above the critical level has the potential to mitigate the sharp production decline in tight formations and therefore enhance ultimate hydrocarbon recovery.
Laplace Domain Coupled Dual Continuum and Embedded Discrete Fracture Model for Rate Transient Analysis in Low Permeability Reservoirs
Authors: Fang Sidong , Cheng Linsong , Huang Shijun , Renyi Cao
Published: April 2016

Modeling transient flow of horizontal wells with complex fracture networks is attractive and challenging topic for economically exploitation of low permeability reservoirs. Previous works have been done by employing analytical, semi-analytical and numerical models to solve this problem. The analytical trilinear-flow is not capable to capture the shapes and distributions of stimulated reservoir volume (SRV), while semi-analytical source function method doesn't consider natural fractures. In the paper, we developed a hybrid coupled approach to combine the embedded-discrete-fracture model (EDFM) and dual continuum representation in Laplace domain. The transient dual porosity with various matrix-block size is implemented to incorporate the fracture spacing and the petro-physical characteristics of flow from tight matrix to natural fractures. Large scale hydraulic fractures are explicitly modeled using embedded-discrete-fracture model (EDFM) as the source terms in the systems. Other than the equivalent distance and finite difference method used in EDFM, a novel element-based numerical method called mixed boundary element method is developed to rigorously capture the transient flow behavior of hydraulic fractured systems and couple the above models in triangle grids. Several examples in this work are presented to show the robustness, applicability and computational convenience of the hybrid approach for the rate transient and pressure transient analysis of low permeability oil and gas reservoirs. The proposed model is validated by comparing the results against both analytical trilinear solutions and other numerical solutions. In addition, the method provides maximum flexibility of representation for complex fracture systems both in pressure transient analysis and production forecast.
Innovative method for recovery and valorization of hydroxytyrosol from olive mill wastewaters
Authors: Bonetti A. , Venturini S. , Ena A. , Faraloni C.
Published: April 2016

The nutritional properties of olive oil can be attributed to its oleic acid and phenolic compounds content, acting as natural oxidants to prevent human diseases. In particular, hydroxytyrosol has an anti-inflammatory action similar to omega 3 fatty acids from fish oil. The olive oil production was conducted by two extraction procedures: first, a two-phase extraction giving extra-virgin olive oil and humid pomace, second, a three-phase working process of humid pomace, obtaining another minimum quantity of extra-virgin olive oil, ‘dry’ pomace devoid of polyphenols, and mill wastewaters rich in anti-oxidant compounds. The aim of this processing was to employ water to extract the highest concentration of polyphenols from humid pomace and convey them in oil mill wastewaters for extraction. Processed olives were 37,200 kg, pomace deprived of polyphenols was equal to 20,400 kg and processing was performed with 500 kg of olives per hour. This method offers advantages of using cheap equipment and technical simplicity.
Retraction: 7-nitroindazole, a selective neuronal nitric oxide synthase inhibitor in vivo prevents kainate-induced intrahippocampal neurotoxicity. Radenovic L, Selakovic V, Bozic B. Arch Biol Sci. 2005;57(2)75-81. DOI: 10.2298/ABS0502075R
Authors: Editorial E
Published: April 2016

The article: 7-Nitroindazole, a selective neuronal nitric oxide synthase
inhibitor in vivo prevents kainate-induced intrahippocampal neurotoxicity.
Radenovic L, Selakovic V, Bozic B. Arch Biol Sci. 2005;57(2)75-81, repeats
data already published in: 7-Nitroindazole reduces nitrite concentration in
rat brain after intrahippocampal kainate-induced seizure. Radenovic L,
Vasiljevic I, Selakovic V, Jovanovic M. Comp Biochem Physiol Pt. C. 2003;135
443-50, without any referencing.

 Link to the
retracted article <a
href="http://dx.doi.org/10.2298/ABS0502075R">10.2298/ABS0502075R