bluuebunny/crossref_metadata_2025 huggingface dataset:
Case History: An Enhanced Solids Control Strategy Selective Flocculation Process Allows for Reduced Dilution Rates and Costs in Water-based Drilling Fluids in Auca Field, Ecuador
Authors: Costa Sergio , Maiquiza Klever , Serrano Mario , Bastidas Alejandro , Enriquez Jose
Published: January 2016

The main objective of using selective flocculation is to increase the efficiency of the fluid system and the solids-control equipment. Removing drill cuttings from the fluid system is important for increasing the drilling efficiency and success of the overall operation. Selective flocculation is proven to efficiently remove drilled solids, especially smaller- or colloidal-sized particles. The performance of drilling fluid components increases because larger quantities are allowed to interact with the drilled formation, which is preferred.

This process provides various benefits, including decreased water consumption, which reduces requirements for additional new fluids to be mixed for dilution and consumption of sustaining properties for rheology, filtration control, and inhibition.

The design process focuses on the operation of centrifuges but begins by performing a detailed evaluation using specialized equipment of all solids-control equipment available on the drilling rig, from the shakers to centrifuges. Damaged parts and accessories are repaired and/or replaced, and a simple barite retrieval system and an array of valves for the injection of a concentrated flocculant solution composed of a specialized clay polymer are installed in the centrifuges.

The flow necessary for operation of the centrifuges is separated from the drilling circuit as the design current. The specialized polymer solution is injected, and the process ends with the arrangement of injection rates to obtain an output current with a clay content value measured using a methylene blue test (MBT) at zero or near zero. This current's properties must remain close to those of a new fluid without weighting material.

When the treatment was evaluated, an increase in solids-control equipment efficiency of approximately 10% was obtained, and a 12% reduction in total new drilling fluid volume was observed, which could be optimized up to approximately 30%. Savings in water consumption were directly proportional, and cost savings were influenced by the reduced consumption of fluid products.
Drilling Improvements in Pursuit of the Perfect Well in the Eagle Ford - More than 52% Reduction in Drilling Time and 45% in Cost in Two and a Half Years
Authors: Coletta Claudio J. , Arias Camilo , Mendenhall Scott
Published: January 2016

Drilling time and cost were reduced in the Eagle Ford through the implementation of techniques and processes that resulted in 52% improvement in time and 45% reduction in cost.

The shale revolution sparked an aggressive development campaign starting in 2010 in the Eagle Ford. Wells were drilled with a lack of appropriate knowledge of the area, without sufficient experience or proper equipment. Drilling costs were high but development was profitable due to the surge in oil prices.

Drilling wells in the Eagle Ford is challenging because of the differences in lithology throughout the well, pore pressure profiles, high temperature, geosteering requirements, and casing design. These challenges had to be addressed in the design and execution of the wells. In addition, multiple trips due to downhole tool failures and low rate of penetration (ROP) contributed to high non-productive time (NPT) and associated costs.

When Statoil took over the operatorship in the Eagle Ford an integrated approach to engineering and operations was key to optimize performance and bolster understanding of the area. Application of technology and standardization of operations resulted in continuous performance improvement. Detailed planning and execution, application of rotary steerable, implementation of an optimized casing design, contractor performance management, clear and open communication within the team, implementation of a performance incentive plan, and proper risk management all played a part in the overall drilling performance improvements.

Over the past 2 1/2 years, more than 100 wells have been drilled in the Eagle Ford by Statoil. The techniques and procedures applied to optimize operations resulted in valuable lessons learned that can be applied to other development programs in the Eagle Ford and similar areas.
Use of Historic Data to Improve Drilling Efficiency: A Pattern Recognition Method and Trial Results
Authors: Kristjansson Sean D. , Neudfeldt Adam , Lai Stephen W. , Wang Julian , Tremaine Dean
Published: January 2016

Despite recognition by the drilling industry that historic data can be used to inform the efficiency of drilling operations, published research into methods to systematically exploit historic data for this purpose are relatively scarce. In the present paper, we describe a novel method and automated solution that does just this it was developed for land-based wells drilled on the same pad or in similar geologic formations (i.e., offset wells), and it uses machine learning to search the offset data for epochs of highly efficient drilling. Once these epochs are identified, drilling parameter settings including weight on bit (WOB), drill string or drill bit revolutions per minute (RPM), differential pressure (ΔP), and pump rate (total pump output; TPO) settings linked to the highly efficient drilling epochs are extracted from the offset data. These settings then are formation- and depth-aligned to the new well to be drilled, and they are smoothed and displayed on the electronic drilling recorder (EDR) in real-time as "drilling parameter roadmaps." Such roadmaps were created for surface, intermediate, build and lateral sections for two trial wells. Trial results indicated that the average rates of penetration for the trial wells exceeded the average rates of penetration for the offsets by 20.1% and 47.8%, and time to drill the trial wells (i.e., spud to target depth) took 4.3 and 4.1 fewer days compared to the average number of days for the offsets. Per-day cost to operate these rigs was approximately $80, 000 suggesting our solution yielded substantial cost savings.
Friction Load Redistribution for Robust and Cost Efficient Design of Extended Reach and Horizontal Well Completions
Authors: McSpadden A. R. , Trevisan R.
Published: January 2016

In horizontal and extended reach wells where long completions are run into highly deviated or lateral zones, large compression loads arise due to running friction. These loads remain locked in the string when the packer or cement sets. Dissipation of friction during life service due to string vibrations and movements redistributes these friction loads between the wellhead and packer or top of cement. A numerical approach is presented to calculate the redistributed friction load so that an accurate initial tubing load is implemented in the tubular stress analysis. The proposed methodology offers an opportunity for design optimization via accurate prediction of tubing loads when the locked-in friction loads may be a determining factor in the balance between marginal tension limits near surface and marginal compression loads downhole.

The numerical approach is a simple 1D finite element model in which incremental frictional loads are decomposed and redistributed based on relative stiffness of the string uphole and downhole of each local node. Essentially each portion of the string is represented as a series spring. The methodology requires input of the estimated friction load for each incremental element during running from a standard torque-drag analysis.

The results are particularly relevant for ERD, multistage completion and shale-type multizonal lateral wells, where overestimation of in-service compression above the packer or cement may pose considerable design challenges for tubular components including connections. The common assumption to ignore friction in tubing analysis is non-conservative in that it may underestimate friction loads, especially downhole at the packer. However, applying the full slackoff load downhole is also unrealistic and overestimates compression above the packer leading to costly component selection. Results from the numerical model wherein post-dissipation friction loads are redistributed show that only a part of the friction induced compression migrates to the packer. Some of the redistributed friction load results in additional tension at the wellhead. The type of trajectory, kick off depth and deviation angle are important factors for the load redistribution.

The methodology presented in this work provides an approach to calculate the proportion of friction load transferred to the surface compared to the packer or cement top. The redistributed result which divides the running friction load between hanger tension and downhole compression is not always intuitive. This approach is critical for correct modelling of the initial conditions in the tubing stress analysis with significant impact on tubular cost efficiency and fit-for-purpose design and well integrity.
Nanoparticle-Based Drilling Fluids for Minimizing Formation Damage in HP/HT Applications
Authors: Mahmoud Omar , Nasr-El-Din Hisham A. , Vryzas Zisis , Kelessidis Vassilios C.
Published: January 2016

Drilling fluid must fulfill various functions with a great impact on the drilling performance. Drilling fluid invasion can cause formation damage. Good quality mudcakes can prevent such damage. This research focuses on the lab techniques and performance results of testing innovative water-based drilling fluids containing nanoparticles (NPs) for minimizing formation damage at high-pressure/high-temperature (HP/HT) conditions.

A couette type viscometer was used to examine the rheological properties of the drilling fluids tested in this research. Zeta potential measurements were conducted at different temperatures and concentrations to assess their stability and to investigate the role of charge potential. Indiana limestone outcrops were examined as the filter media for both static and dynamic filtration (up to 350°F and 500 psi) using a HP/HT dynamic filter press. The mudcakes were investigated using a computed-tomography (CT) scan, and Scanning Electron Microscopy-Energy Dispersive Spectroscopy (SEM-EDS). Inductively Coupled Plasma-Optical Emission Spectrometry (ICP-OES) was used to measure the concentrations of key ions in the filtrate fluids.

A significant reduction in the filtrate fluid volume was achieved when using ferric oxide NPs (-43% for 0.5 wt%) compared to that of the base fluid. However, adding silica NPs led to an increase in the filtrate volume and mudcake thickness. Increasing the NP concentration resulted in an increase in the fluid loss and mudcake thickness. The mudcakes consisted of two layers, as indicated by the CT scan analysis. 0.5 wt% was found to be the optimal NP concentration, which provides less agglomeration and a reduction in the mudcake permeability by −76.4%. At this concentration, the ICP-OES analysis showed a higher cation dissociation, which promoted the formation of a different clay platelet microstructure. At a higher NP concentration, a new layer of NPs was formed in the mudcake, which adversely affects the mudcake characteristics, as demonstrated by CT scan analysis and SEM-EDS elemental mapping. The rheological measurements indicated a good rheology at different temperatures and NP concentrations. Moreover, the NPs helped to stabilize the viscosity and yield stress at high temperatures (up to 200°F). Aging at 350°F for 16 hours showed that NP-based drilling fluids remain stable with minor changes in rheological properties. The obtained rheological data for various NPs is fitted to the classical drilling fluid rheological models to determine the best fit-model, which can then be applied to an efficient design.

This research provides a comprehensive evaluation of improved water-based drilling fluids, using ferric oxide and silica NPs for HP/HT applications. The examined NPs have the potential to enhance drilling fluid properties, which provides more efficient drilling operations and less formation damage.
Factors Governing the Performance of Multi-Layered Metal-Mesh Screens
Authors: Wu Chu-Hsiang , Sharma Mukul M. , Chanpura Rajesh , Parlar Mehmet , Ayoub Joseph
Published: January 2016

Multi-layered metal-mesh screens (MMSs) are widely used as stand-alone screens for sand control in unconsolidated formations. The nominal rating of such screens is usually based on the specifications of the filter layer. It is often found that screens with the same filter layer nominal rating perform differently. It is shown in this study that the primary reason for this is that the sand retention performance of multi-layered MMSs is a strong function of not only the filter layer but also the protection and the support layers.

This paper presents a systematic study that shows how the overlap between different mesh layers, the alignment of the protection and support layers, and the relative pore size ratio, defined as the ratio of pore size of the protection/support layer to that of the filter layer, have a large impact on the sand retention performance of a MMS. The pore size distribution (PoSD) of multi-layered plain square mesh (PSM) and plain Dutch weave (PDW) screens are calculated using a novel numerical technique. Influences of screen-sintering, coupon-sampling, and screen designs on PoSD of a screen are modeled by varying the layer-overlap, shifting the layer-alignment, and modifying the design of the protection and support layers. The PoSD data is used as an input into a validated analytical model for evaluating sand production of PSM screens in slurry type sand retention tests (SRTs) for screen design optimization.

For PSM screens, the results show that the PoSD of a multi-layered screen can be very different from the PoSD of the filter layer. In general, a decrease in sand production with an increase in layer-overlap is observed; the trend exists irrespective of how mesh layers are aligned. A change in mesh alignment is found to cause a variation in sand production even with the same filter layer pore size and layer-overlap. The nominal rating of the filter layer of a multi-layered PSM screen should be used to estimate sand production only when the pore sizes of the protection and support layers are much larger than the pore size of the filter layer. For PDW screens, layer-overlap is shown to dominate the screen performance by affecting the filter layer pore size. PoSD of a PDW screen is found to be less affected by variations in layer-alignment and relative pore size ratio.

This study clearly shows that layer-overlap, layer-alignment, and relative pore size ratio between mesh layers can have a significant impact on the sand retention performance of a multi-layered MMS. These factors are seldom considered when selecting a screen. As such widely different screen performances can be expected for screens with the same nominal screen rating. Our results have a direct bearing on how MMSs are manufactured, selected, and specified. Increasing the relative pore size ratio appears to be a promising screen-design approach for obtaining consistent screen performance for multi-layered MMSs.
Targeting Enhanced Production through Deep Carbonate Stimulation: Stabilized Acid Emulsions
Authors: Cairns Amy J. , Al-Muntasheri Ghaithan A. , Sayed Mohammed , Fu Liling , Giannelis Emmanuel P.
Published: January 2016

To meet rising global demands for energy, the oil and gas industry continuously strives to develop innovative oilfield technologies. A large portion of the world's oil and gas reserves are trapped in carbonate reservoirs, particularly in the Middle East. Well stimulation treatments for these highly heterogeneous formations have traditionally relied upon the use of strong mineral acids, e.g. hydrochloric acid (HCl). However, fast rock/acid reaction rates and corrosion issues pose a significant challenge to the longevity and practical application of such treatments. Alternative approaches have been proposed to slow down this process, among the most popular being emulsified acids. In this case, the release mechanism of live acid is governed by droplet contact with the surface of the formation in conjunction with suitable downhole conditions (i.e., temperature, pressure, pH). Upon release, the acid proceeds to rapidly react with the carbonate formation thereby unveiling a conductive wormhole network.

This paper presents a systematic experimental study targeting deeper well stimulation using an improved emulsified acid system. The current study demonstrates the success of an emulsion-based system that is stable at elevated temperatures (e.g. up to 300°F/150°C) for a prolonged period of time. To gain a deeper understanding of the dissolution behavior and resultant wormhole morphology, a systematic coreflood study was conducted to identify key parameters that influence the overall performance of the newly developed stabilized emulsified acid. The parameters investigated include: (1) pore pressure, i.e. up to 7,000 psi, (2) flow rate, i.e. up to 5 cm3/min, (3) acid-rock contact time, and (4) fluid treatment composition.

Indeed, the stabilized emulsified acid exhibited superior performance as confirmed from coreflood experiments performed at 3,000 psi and 300°F. In this study, 0.65 PV of fluid was injected into a 12″ core and shut-in for a period of 15h, thus giving the emulsion ample time to break in all cases. Interestingly, a 3-fold enhancement in carbonate permeability was observed for the stabilized emulsified acid as compared to the conventional acid-in-diesel emulsion.

Moreover, the CT images for the treated core samples show that the stabilized acid system had less face dissolution and had the desired wormhole characteristics, i.e. narrow and directional propagation behavior with deeper penetration into the core sample. Finally, additives were defined and used to improve the performance of emulsified acid systems at high temperature, which in turn improved the acid penetration rate and wormhole propagation.
Fines Mobilisation by Low-Salinity Water Injection: 3-Point-Pressure Tests
Authors: Bhattacharya S. S. , Paitaridis J. , Pedler A. , Badalyan A. , Yang Y. , Carageorgos T. , Bedrikovetsky P. , Warren D. , Lemon N.
Published: January 2016

Fines mobilisation and straining by changing the ionic strength of the reservoir water results in a significant permeability reduction, and is a well known mechanism of formation damage. The phenomenon occurs during drilling and completion, where the fluid invasion with fines lifting may cause significant productivity damage. The paper experimentally investigates the permeability damage of natural sandstone rocks in order to select ionic compositions for drilling and completion fluids.

Two sandstone rock cores from the same production well from the Birkhead Formation in the area of underlying Patchawarra Trough (Eromanga Basin, Australia) were chosen to study formation damage during successively decreasing (piece-wise) the ionic strength of injected fluid using a three point pressure measurement method along the core. Effluent particle concentration and electrolytic conductivity were measured for effluent streams. It was observed that formation damage in the studied rock cores after their contact with low-ionic strength fluid is caused by fines mobilisation, their migration in the porous medium and straining in thin pores. Each coreflood is characterised by decreased rock permeability with stabilisation times significantly exceeding one pore volume, suggesting that mobilised particle’s drift velocity is significantly lower than that for a carrier fluid. The electrolytic conductivity profile shows that the fluid front in porous medium is not piston-like, rather diffusion driven, suggesting that there is an additional reason behind long permeability stabilisation time – a delayed contact of rock with low ionic strength fluid.
A Simulation Study on Mitigation of Water Hardness Damages in Fracturing Fluids
Authors: Bao Chen , Han Jiahang , Li Leiming , Qiao Changhe , Sun Hong , Sookprasong Andy
Published: January 2016

Preparing fracturing fluids from low-quality water such as hard water is an environmentally friendly option in field operations and is therefore highly desirable. However, fluid viscosity can be significantly reduced when mixed in hard water rather than fresh water, requiring the addition of stabilizers to mitigate the hardness damages. Although some stabilizers have already been identified in experiments, systematic studies to help optimize fracturing fluids based on chemical compositions of produced water and the chemical properties of polymer and stabilizers are still needed. In this work, we use reactive transport model to understand how stabilizers mitigate water hardness damages in fracturing fluids prepared with hard water.

We studied a system where several stabilizers have been proved to mitigate hard water damages to metal-crosslinked derivatized polysaccharide (MCDP) fracturing fluids. Reversible chemical reactions between MCDP and cations lead to polysaccharide salts precipitations that compromised the fluid viscosity. Stabilizers are chemically active substances that preferentially react with cations, especially divalent cations so they can protect MCDP from precipitating. To benchmark this system, reactive transport models were set up to explicitly consider the fluid viscosity alterations caused by the chemical reactions among polymers, cations and stabilizers in flow conditions relevant to regain conductivity tests (RCT). The numerical simulator was developed based on Crunchflow with the viscosity as a function of polymer and cation concentration.

The viscosity profiles of a number of rheology experiments were first matched as model calibrations. The effects of different stabilizers were then determined by parametric comparison of different cases. The model was then verified by matching it to the rheology of fracturing fluids prepared in experiments by mixing MCDP and stabilizers with hard water samples. Simulation results show that the type of stabilizers and cations in the hard water has a significant impact on the viscosity alteration for the same level of MCDP added. Stabilizers mitigate the hardness damages either instantly or in a latent manner depending on their intrinsic reaction kinetics with cations.

This work demonstrates that reactive transport model could be used to help design and optimize fracturing fluids according to laboratory tests and produced water compositions. It is believed to be the first time that reactive transport modeling is used to study the complicated interactions among polymers, cations and stabilizers in fracturing fluids.
Chlorophyll: A Naturally Occurring Green Polymer Breaker for Hydraulic Fracturing
Authors: Dhulipala Prasad D. , Armstrong Charles D.
Published: January 2016

Porphyrins produce free radicals in alkaline conditions. Chlorophyll is an Mg++-containing tetrapyrrole formed from 4 porphyrin rings and is part of the photosynthetic reactions in plants (Arnoff, 1966). It catalyzes carbohydrate synthesis in the presence of light and carbon dioxide. Using the molecular structure of chlorophyll, we hypothesized that chlorophyll functions as a breaker by producing hydrogen peroxide or other radicals in the alkaline environments of borate-fracturing fluids.

This study evaluated leaf extract containing chlorophyll as a potential polymer breaker. Leaves contain 1.5 to 2.5% of chlorophyll in their leaves and the ratio of chlorophyll a to b is 2.5-3.5 depending on growth conditions and light exposure (Willstaetter and Stoll, 1928). Chlorophyll samples were obtained from various plants and commercial sources, and their efficacy as polymer breakers was studied against guar-based fracturing fluids. The average molecular weight of treated fluids was measured by changes in intrinsic viscosity. Additionally, regain conductivity measurements were carried out. Results showed an 84% regain conductivity in proppant packs. Chlorophyll-treated cross-linked fluids showed a more than 90% viscosity reduction, without any viscosity rebound on cooling. The chlorophyll worked efficiently up to 250°F but the optimum temperatures are at 175 to 200°F with narrow pH range of 9.5 to 10. The chlorophyll-treated fluids also showed a reduction of molecular weights of the linear guar polymer from 1,472,000 to 138,000 as measured by the intrinsic viscosity method. The studies support the hypothesis that chlorophyll can function as a polymer breaker for alkaline fracturing fluids.
First Successful Application of Temporary Gel Plug Replacing Calcium Carbonate Chips to Isolate Depleted Reservoir, Case Study from Saudi Arabia Gas Field
Authors: Ziad Abdullah Bin , Gromakovskii Dmitrii , Al-Sagr Abdulaziz , Al-Driweesh Saad
Published: January 2016

Deposition of scale is one of the most common and serious problems seen in HPHT gas wells in Saudi Arabia. A Coiled Tubing intervention to mechanically clean out the scale deposits from the production tubing and liner has been the most common approach to address the problem. Since reservoirs get depleted with time, lost circulation becomes a severe issue. In wells that cannot support a column of fluid due to low reservoir pressure, the reservoir (open-hole, perforations) needs to be isolated to regain full circulation that allows to lift the milled scale to surface. A conventional procedure to isolate the reservoir is to use Calcium Carbonate chips until leakoff into the formation is controlled. This approach is successful in isolating, but presents significant disadvantages regarding the amount of chips needed to successfully isolate, and, more importantly, the cleanout of this solid material once the de-scaling operation has been concluded.

This paper discusses the first successful reservoir isolation using exclusively a temporary gel plug that allowed safe and successful execution of a mechanical de-scaling operation without using CaCO3 chips. Temporary gel plugs are normally polymers dispersed in water that can be either crosslinked or non-crosslinked. Well variables like well configuration, bottom-hole temperature; desired plug stability as well as operational variables such as pump rates and placement times are used in selection and design of the type of plug to be used. In the specific case of the reservoir isolation needed to perform a de-scaling operation, a delayed crosslinked polymer gel plug that generates over time a firm and highly viscous gel was used. This temporary gel plug was placed by bullheading two batches of this system down to the top of the openhole wellbore section and allowing an 8 hours setting time to crosslink and isolate the low pressure zone where fluid will leakoff thus generating a lost circulation. The reservoir isolation was confirmed by positive pressure testing the plug. The specific temporary gel plug was designed to be readily soluble in acid in order to restore communication with the reservoir and resume gas production without a need for any additional cleanout runs with Coiled Tubing and use of large fluid volumes.
Novel Aqueous-Based Consolidation Restores Sand Control and Well Productivity: Case History from East Malaysia
Authors: Riyanto Latief , Saleh Malaz , Goh Kellen , Ambrose Jonathan , Kristanto Tutus , Hong Chua Yek
Published: January 2016

The integrity of sand control method is often compromised as wells get older and the field becomes more mature. An operator in East Malaysia pursued a cost-effective alternative remedial sand-control solution to restore the functionality of its sand control completion and provide unhindered oil production in a well. The well, located offshore Sarawak Malaysia, was a single string oil producer completed in 1987 with gravel pack and screens. It was a producing well for several years until the gravel pack completion failed and the well started to produce excessive sand. The well was beaned down (BD) to achieve an acceptable sand production limit by the operator of below 15 pound per thousand barrels (pptb). The initial remedial sand control measure was to install a thru-tubing screen, hung inside the production tubing. The thru-tubing screen failed to control the formation sand and a second 200 micron thru tubing screen was installed. That screen managed to control the sand production at acceptable levels but induced significant pressure drop, which reduced the oil production from the optimum level of production.

Workover (WO) operations would involve pulling the existing completion, and re-gravel packing the zone would be costly. In addition to cost, induced mechanical skin in a gravel pack might not be lower than thru-tubing screen application. Chemical consolidation treatments using solvent-based resins historically have been used successfully as alternatives to remedial sand control, although their application, has typically been limited to short intervals.

An aqueous based consolidation resin was developed that provides some advantages compared to conventional solvent based resin systems. The aqueous based resin system uses an internally cured water-based epoxy resin. Unlike the solvent based resin systems, which have a low flash point, the aqueous base consolidation resin system is not flammable. It is safer and less complex operationally. The consolidation-fluid mix can also be foamed for diversion purposes to treat wells with relatively large variations in permeability over longer zones compared to the solvent based resins. This paper describes the treatment background, engineering approach, laboratory testing, fluid design stages, quality assurance/quality control (QA/QC) procedures, and the treatment execution for the chosen well. The field trial showed no sand was produced after treatment. In fact, the production rate was twice that of the production rate with the thru tubing screen in place. The promising result from this well creates new opportunities for simple, environmentally acceptable, and cost-effective remedial sand-control solutions for the operator.
Developments in Sandstone HF Acidizing: HF Fluid Compatible with Na or K Brines and Carbonate-Laden Mineralogy for High Temperatures (360°F)
Authors: Garcia Enrique A. , LaBlanc Alyssa , Beuterbaugh Aaron , Calabrese Tristen
Published: January 2016

Using hydrofluoric (HF) acid for the removal of clays and silica minerals impairing permeability in sandstone formations requires fluids free of sodium or potassium ions. High temperatures (> 300°F) further limit HF acid use and its effectiveness because of potentially damaging effects to the formation and its corrosivity. This paper discusses laboratory testing of an aminopolycarboxylic acid (APCA) fluid containing 1 to 1.5% HF acid and highlights its advantages and differentiating characteristics with respect to previous HF acid fluids.

Core flow testing at 360°F was conducted on outcrops of two types of sandstone representing a heterogeneous (65% quartz and illite/kaolinite with feldspars) and a clean (95% quartz) type of mineralogy. The APCA fluid containing HF acid, which incorporates a modulating agent for the HF acid-secondary reaction on aluminosilicate minerals, was compared to the pure APCA (pH 2) fluid and formic acid. Effluent analysis of the spent fluid was completed by inductively coupled plasma (ICP) optical emission spectroscopy (OES). Corrosion inhibition testing was completed for coiled tubing (CT) and carbon steel (NT-95) up to 360°F, employing various classes of inhibitors.

Using an APCA chelating agent in sandstone HF acidizing expands the temperature range of application and the type of minerals that can be exposed to such fluid. High-temperature HF acidizing is also delimited by the type of steel tubing that can be exposed to such fluid, placing significant demands on corrosion control. Laboratory results obtained in this investigation demonstrate that corrosion can be well managed for a fluid having a pH of 2.5 and HF acid concentrations of 1 to 2% from 250 to 275°F and at 300°F with a pH of 4. Testing results show that the APCA/HF fluid, having a pH of 2.5, can effectively be used to treat heterogeneous sandstone of moderate carbonate content at 360°F and is also compatible with a clean sandstone. The APCA/HF fluid stabilizes the most problematic ions in the spent fluid—Al3+, Fe2+/3+, Ca2+, and alumino-fluorides—without the need for acid preflushes and without maintaining highly acidic conditions. Comparison to formic acid and HF acid-free APCA fluid is presented.

Using aminopolycarboxylic acid-type chelants is restricted by the materials commercially available, all of which contain sodium, with one exception, which has ammonium. Hence, HF acidizing has been restricted to ammonium-containing fluids. A differentiating characteristic of the fluid reported here is its ability to sustain Na+ concentrations exceeding 1 M and K+ concentrations in excess of 0.5 M. Furthermore, it is suitable for the treatment of carbonate-laden mineralogy formations up to 360°F.
Iron Sulfide Scale Deposition in Deep Sour Reservoirs
Authors: Ma Jun , Fuss Tihana , Shi Jingyu
Published: January 2016

Crude oil and natural gas can carry various high-impurity products which are inherently corrosive, such as, carbon dioxide (CO2) and hydrogen sulfide (H2S). These impurities increase operational safety risk and can be detrimental to production, both in terms of equipment damage and permeability impairment caused by scale deposition. Problems with iron sulfide scale occur when H2S comes in contact with spent acid solutions containing dissolved iron ions. While dissolution of pipe and iron bearing core materials in H2S solutions is known to result in FeS scale deposition, the reactivity of iron containing proppant material under sour conditions is poorly understood and documented.

The present study evaluates and compares dissolution kinetics of iron bearing formation and ceramic proppants, which were derived from multiple sources of bauxite minerals, in H2S acid solution in order to evaluate their relative contributions to iron sulfide scale deposition. The study uses X-ray diffraction (XRD) and inductively-coupled plasma optical emission spectroscopy (ICP-OES) analysis to qualify Fe containing crystallite forms and quantify dissolution and scale build up reaction kinetics. Scanning Electron Microscopy (SEM) is used to evaluate surface morphology changes associated with iron dissolution and iron sulfide scale deposition. Finally, reactivity of all tested materials is compared based on their initial iron concentration and relative dissolution affinity.
An Integrated Study of Mud Plastering Effects for Reducing Filtrate's Invasion
Authors: Ezeakacha C. , Salehi S. , Ghalambor A. , Karimi M.
Published: January 2016

Drilling fluid's filtration and mud cake build up is often cited as one of the key factors where operators observed better control of lost circulation from one well to another. Although this may sound a routine and simplistic process, it is quite complex. To understand a true synthesis of mud cake build up, one needs to study effects of mud composition, viscosity, and fluid mechanics involved, filtration permeability, and erosion and depositional factors. In addition of these factors, there are effects of time, pressure and temperature.

In this study, a synthesis of mud filtration and mud cake build up by conducting laboratory experiments is presented. The study presents results for Non-aqueous Oil Based Muds (OBM). The methodology depends on conducting Permeability Plug Testing (PPT), SEM and EDS analysis of mud filtrates and mud cakes. We present analysis in different time spans to capture time effects for tests in high pressure and temperature conditions. Other experimental variables in this work are permeability and heterogeneity of filtration medium which are implemented by using different rock disks.

A combination of SEM study of filter-cake structures with the evaluation of experimentally determined fluid loss data leads to a better understanding of the basic principles of filter-cake buildup and formation damage. The key findings from this study are the effects of filtration medium on cumulative mud filtrate loss, invasion and mud cake characterization, and its permeability. This could not be achieved by using ceramic disks traditionally used for PPT experiments. Effects of core permeability variation on mud invasion under high pressure and high temperature conditions have been illustrated.
Consolidating Sand with New Generation Zeta Potential Altering Systems
Authors: Treybig D. S. , Saini R. , Vigderman L. , Smith K. , Gray B. , Strobel J.
Published: January 2016

This paper describes a new zeta potential altering system (ZPAS) that is based on an inner salt developed between an organic polymer (OP) and an ester for fines, sand and proppant flowback control. The objective of this work was to develop a ZPAS with an enhanced environmental profile and better product performance as it relates to intensity of particle agglomeration and thermal stability under wide range of downhole operating conditions.

The effect of molecular weight of the organic polymer after blending with different esters on zeta potential, rheology, agglomeration, fines production, sand production, regain permeability, fracture conductivity, flash point and EC50 concentration was investigated and compared to the performance of the existing ZPAS. Zeta potential was measured using a Zetasizer Nano Z System manufactured by Malvern, rheology with Anton Paar and ARES G2, sand production with a Maximum Sand Free Rate (MSFR) Test, regain permeability with a Chandler Engineering Formation Response Tester, fracture conductivity, indentation force with a Texture Analyzer, flash point with Miniflash FLP/FLPH/FLPL and EC50 concentration with a Modern Water Microtox Model 500 Analyzer.

When the organic polymer was blended with an ester, the odor was minimized substantially and toxicity reduced 400 times as compared to the current ZPAS. This organic polymer has a considerably higher molecular weight than the prior oligomeric ZPAS system. 1 This molecular weight enhancement improves the degree of agglomeration as measured by indentation testing and provides better thermal stability. Force in grams as measured with the indentation tester increased as the organic polymer concentration and molecular weight was increased in the new ZPAS formulation. The force in grams is an indicator of the effectiveness of sand consolidation. There was no sand produced at 180° F with 20/40 mesh sand and a confining pressure of 400 psi in the MSFR test. Regain permeability of 60 to 82% was obtained in low permeability sandstone. High MW ZPAS was more effective than medium MW ZPAS at 2,000 psi closure stress while medium MW ZPAS was more effective at 6,000 psi closure stress. The oscillatory rheometer indicated that the polymeric ZPAS is a Newtonian fluid which makes it easy to pump. After sand is agglomerated with the ZPAS, the agglomerated sand becomes viscoelastic. The elasticity is maintained to a temperature of at least 180°F. The stronger sand consolidation and more deformable agglomerate provided by this new generation ZPAS as compared to the current ZPAS is useful in producing more oil without incremental sand production.
Injectivity Impairment During Produced Water Disposal into Low-Permeability Völkersen Aquifer (Compressibility and Reservoir Boundary Effects)
Authors: You Z. , Kalantariasl A. , Schulze K. , Storz J. , Burmester C. , Künckeler S. , Bedrikovetsky P.
Published: January 2016

Compressibility needs to be accounted for when estimating injectivity decline for water disposal in gas reservoirs and in closed aquifers, and for waterflooding of gas-condensate fields. The problem with given wellbore pressure at the injector aims avoiding the reservoir fracturing. An analytical model is developed that provides well injectivity index decline with time. Under this model, the solution of damage-free compressible flow in a closed reservoir is asymptotically matched with the impedance growth formulae for incompressible flow in the well vicinity. For the well regime of a given wellbore pressure, the injection rate decline is described by a nonlinear integro-differential equation that is solved iteratively. The solution under the field conditions investigated shows that well impedance grows faster during deep bed filtration than during external cake formation. This unusual pattern is explained by low permeability of the reservoir. Well impedance is more sensitive to the effect of formation damage than to the compressibility effect of rock and water. Lower formation damage, higher compressibility, or lower injected particle concentration results in larger total injection volume into a closed reservoir.
Molecular Dynamics Simulations of Asphaltene Dispersion by Limonene and PVAc Polymer During CO2 Flooding
Authors: Sedghi Mohammad , Goual Lamia
Published: January 2016

Asphaltene precipitation during miscible CO2 flooding can adversely affect the productivity of reservoirs during the course of oil recovery. The prevention of formation damage ensuing from asphaltene deposition in porous rocks often requires the use of chemical additives such as solvents or inhibitors. Effective additives are able to disperse asphaltene aggregates by curbing their growth in the bulk phase. While numerous dispersion studies have been performed in alkane solvents, very limited work currently exists in supercritical (sc) carbon dioxide. The main challenge stems from the inherent insolubility of a large number of additives in sc-CO2. The objective of this study is to investigate the molecular interactions between asphaltenes and two environmentally friendly additives in sc-CO2 at 308 K and 300 bar using molecular dynamics (MD) simulations. The additives consist of a terpene solvent (d-limonene) and a common viscosifier (polyvinyl acetate or PVAc). Two similar asphaltene structures (with and without hydroxyl group) were designed in order to understand the role of hydrogen bonding in their aggregation behavior. The results indicate that d-limonene can only disperse non-hydrogen bonding asphaltenes when used in sufficient amounts (i.e., 30 wt%). The interactions between hydrogen bonding asphaltenes and PVAc polymer (5 wt%) significantly reduced their aggregation but lowered the solubility of the polymer in sc-CO2. Adding limonene to this mixture could remediate the phase change and maintain asphaltenes and PVAc completely dispersed in the system.
Multi‐Profile Analysis of Soil Moisture within the US Climate Reference Network
Authors: Coopersmith E.J. , Cosh M.H. , Bell J.E. , Crow W. T.
Published: January 2016

Core Ideas

Hydraprobe measurements can be quantified.

USCRN gauges distributed nationally are analyzed.

Random error magnitudes are a function of how recently precipitation has occurred.

Soil moisture estimates are crucial for hydrologic modeling and agricultural decision‐support efforts. These measurements are also pivotal for long‐term inquiries regarding the impacts of climate change and the resulting droughts over large spatial and temporal scales. However, it has only been the past decade during which ground‐based soil moisture sensory resources have become sufficient to tackle these important challenges. Despite this progress, random and systematic errors remain in ground‐based soil moisture observations. Such errors must be quantified (and/or adequately minimized) before such observations can be used with full confidence. In response, this paper calibrates and analyzes US Climate Reference Network (USCRN) profile estimates at each of three sensors collocated at each USCRN location. With each USCRN location consisting of three independent, Hydraprobe measurements, triple collocation analysis of these sensory triads reveals the random error associated with this particular sensing technology in each individual location. This allows quantification of the accuracy of these individual profiles, the random errors associated with these measurements in different geographic locations, and offers the potential for more adept quality control procedures in near real time. Averaged over USCRN gauge locations nationally, this random error is determined to be approximately 0.012 m3/m3.
Tangent Line/Second‐Order Bounded Mean Oscillation Waveform Analysis for Short TDR Probe
Authors: Wang Zhuangji , Lu Yili , Kojima Yuki , Lu Songtao , Zhang Meng , Chen Yan , Horton Robert
Published: January 2016

Core Ideas

• A new method for analyzing TDR waveforms is presented.

• The method provides consistent results on waveforms obtained from short TDR probes.

• The method is stable enough for automatic implementation on large sets of TDR waveforms.

Tangent line (TL) methods and the second‐order bounded mean oscillation (BMO) method have been proposed for determining the reflection positions of time domain reflectometry (TDR) waveforms, especially for short‐probe TDR sensors. However, the accuracy of TL methods is limited by the multi‐reflection effects of the short‐probe TDR sensor, and an automatic implementation of the second‐order BMO is challenging because of the superimposition of the TDR waveforms. In this study, we combined a TL method with second‐order BMO to develop a tangent line/second‐order bounded mean oscillation (TL‐BMO) method. Laboratory and field data were used to evaluate the TL‐BMO method. Separate tests were performed on laboratory data to compare the TL‐BMO method with the TL method and the second‐order BMO method. For selected waveforms, the TL‐BMO was more accurate than the TL method (the RMSE of TL‐BMO was 0.0197 m3 m−3 and the RMSE of the TL method was 0.1071 m3 m−3). The TL‐BMO was able to avoid calculation errors associated with automatic analysis by the second‐order BMO (RMSE of TL‐BMO automatic analysis was 0.0199 m3 m−3 and the RMSE of second‐order BMO automatic analysis was 0.1414 m3 m−3). For analyzing field measurements, the TL‐BMO method was able to determine soil water contents accurately during a 3‐wk‐long measurement period. Conclusively, the new TL‐BMO method was more accurate than the TL method, and it demonstrated the stability necessary for automatic analysis of short‐probe TDR sensors.
Disentangling the Effects of Land Management and Soil Heterogeneity on Soil Moisture Dynamics
Authors: Hohenbrink Tobias L. , Lischeid Gunnar , Schindler Uwe , Hufnagel Johannes
Published: January 2016

Core Ideas

We performed time series analysis of existing large soil moisture data sets.

Observed behavior was decomposed into respective contributions of single processes.

Considering input signal transformation instead of mass flux considerations.

Our approach opens many new possibilities to analyze complex soil system behavior.

Soil moisture is the essential control of water and energy dynamics at arable sites. Time series of soil moisture reflect the interplay of various processes, each of which influences the overall soil moisture dynamics. In this study we tested an approach to break down observed soil moisture behavior into the respective contributions of individual processes. We applied a principal component analysis to soil moisture time series from a field experiment comprising two crop rotation systems and two different soil tillage practices. We concentrated on 57 soil moisture time series measured over nearly 4 yr at 12 plots and five soil depths, down to 1.5 m. About 77.9% of the variance was reflected by the first component being almost identical to a time series of averaged soil moisture. It described the effect of the meteorological boundary conditions. The second component described the effect of the input signal damping increasing with soil depth and accounted for 7.8% of total variance. The signal transformation over depth proved to be more or less uniform throughout the test site, despite considerable soil heterogeneity. Another 3.6% of the total variance (third component) was unambiguously explained by the different cropping systems. On the contrary, different soil tillage practices had no significant effect. The suggested approach opens up many possibilities to analyze and better understand complex soil system behavior. The data‐based approach of time series analysis provides model‐independent, quantitative information about the key factors and processes controlling soil water dynamics. Hence, it is especially valuable for model building, calibration, and evaluation.