bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation of Single Cutter Experiments in Evaporites through Finite Element Method
Authors: Martinez Ingrid Reyes , Fontoura Sergio , Inoue Nelson , Carrapatoso Carla , Lourengo Affonso , Curry David
Published: June 2014

Single cutter laboratory experiments are used for evaluating the drill bit - rock interaction mechanisms. These experiments can be simulated through numerical methods in order to analyze particular conditions of each borehole drilling operation. This paper describes the use of Finite Element Method for modeling single cutter experiments in evaporites. The constitutive model of Drucker-Prager, calibrated using results of triaxial compression tests carried out in evaporites, was used to model the rock behaviour. Also, an isotropic damage model was employed for modeling the erosion mechanism that represents the rock-cutter interaction. The model demonstrated good agreement with experimental results.

A series of numerical experiments were carried out in order to observe the cutting process under different geometrical conditions. Two-dimensional and three-dimensional simulations were performed to analyze the variation of Mechanical Specific Energy (MSE) required to cut rock by varying three parameters: Depth of Cut (DOC), cutter geometry, particularly the back rake and side rake angles, and confining pressure. It is predicted that MSE decreases when increasing the depth of cut until stabilizing at a certain limit after which it remains substantially constant With regards to the cutter geometry, the results showed that high back rake and side rake angles produce elevated MSE making the process less efficient. The confining pressure analysis showed similar results to the experimental observations found in literature and those performed at our laboratories. The cutting process showed a considerable increase in MSE with the increase of confining pressure.
Advanced Dynamic Training Simulator for Drilling As Well As Related Experience from Training of Drilling Teams with Focus on Realistic Downhole Feedback
Authors: Ødegård Sven Inge , Risvik Bjørn T. , Bjørkevoll Knut S. , Mehus Øystein , Rommetveit Rolv , Svendsen Morten
Published: June 2014

The paper presents a highly advanced training simulator that combines an advanced top-side simulator with a dynamic downhole simulator with an advanced transient integrated hydraulics and thermal wellbore model and a dynamic torque and drag model. The simulator is aimed at drilling and well operations, and is able to handle most of the normal operations, including high pressure high temperature (HPHT) wells, through-tubing rotary drilling (TTRD), extended reach drilling (ERD) and managed pressure drilling (MPD).

The underlying simulator technology is modular, allowing for new modules to be added at a later stage. For instance, MPD control systems can easily be added to the simulator, allowing for training on an MPD operation with both the drilling crew and the MPD supplier. The simulator is able to use pre-programmed scenarios, replay, fast forward and rewind to facilitate efficient training and review sessions

Moreover, the simulator is designed to provide realistic personnel training on emergency procedures and operations such as well control in a safe environment, thereby limiting the human factor in critical operations as well as possibly improving the procedures by frequent use and revision. Also, the simulator allows for integration of HSE in early well planning through simulator training on the actual well to be drilled.

The main innovation is to use dynamic models verified in real-time operations together with an advanced top-side drilling equipment simulator for training on well specific scenarios.

The value added for the industry is to give the drilling and/or engineering teams a possibility to verify and train on identified risk elements prior to drilling a well, as well as retrain during the operation on a "true" virtual copy of the well.

So far more than 60 drilling teams have experience from training, and the feedback has been very positive.

The paper will present the simulator as well as experiences from typical training cases on challenging wells.
Thermal Reactivation of Microfractures and Its Potential Impact on Hydraulic-Fracture Efficiency
Authors: Dahi Taleghani A. , Ahmadi M. , Wang W. , Olson J. E.
Published: June 2014

Core studies have revealed the presence of abundant cemented microfractures in many tight formations. Further independent studies have revealed the opening of some of these microfractures on the wall surface of main hydraulic fractures. In addition, early-production well-testing analysis in some of these cases provides estimates for the hydraulically-induced-fracture surface area, which is much larger than fracture dimensions estimated in fracturing design or provided by the location of microseismic events. Opening of small-sized fractures could be a possible reason for this discrepancy. In this paper, we show to what extent thermal stresses induced by temperature difference between fracturing fluid and formation fluid could provide the driving force to open a portion of these small, cemented natural fractures lying on the surface of hydraulic fractures. Moreover, through combination of stress analysis and empirical fracture-distribution models obtained from outcrops, we calculate the increase of total reservoir/fracture contact surface under the condition of microfracture activation. Our thermoelasticity analysis reveals the effect of the pump rate and temperature of the fracturing fluid on the number of activated microfractures. The results show that the volume of the microfractures varies depending on the length of the microfracture, rock properties, and time. At the end of the paper, through an example, we show that activation of only a small portion of these microfractures can increase the total fracture/formation contact area considerably and, consequently, increase initial production. Reservoir-pressure changes caused by production might partially close or reopen these microcracks during production; hence, the effectiveness of these microfractures could be mainly restricted to the early life of the reservoirs.
Planning the Formation Evaluation Program for Development Financing
Authors: Vance Harold
Published: June 2014

Introduction

During the drilling of a well, certain data must be obtained and interpreted to permit the operator to decide whether or not it will pay him to set pipe in this new well. The money already has been spent to make the hole; if the operator can recover enough production to more than pay completion costs, he probably will set pipe and complete the well.

The purpose of this paper is to show how this same information obtained during drilling can be and is being used to help determine the amount of money a bank will lend the operator, depending upon the income from future production to pay off the loan.

The Banker's Viewpoint

A bank makes most of its money by charging interest on the money it lends. The bank cannot recoup many losses on a 5 to 6 per cent return on the money; therefore, a bank cannot afford to take risks. It should not be expected to take the risks of business because it receives none of the business profits. Some lending agencies do lend money for interest plus an interest in the business after the loan is paid out.

The term "oil and gas loan," as generally used, means a loan secured by a mortgage on a producing property capable of producing future net income from the production of oil and/or gas, with this income being used in whole or in part to payoff the loan while leaving a residue to the borrower. Thus, the primary security is the expected income from the properties; the secondary security is the net worth of the borrower who signed the note.
Thermodynamic Model Improvements for Common Minerals at High Temperature, High Pressure and High TDS with Mixed Salts
Authors: Dai Zhaoyi , Shi Wei , Kan Amy T. , Zhang Nan , Tomson Mason B.
Published: June 2014

Deep water oil and gas production has been challenged due to limited knowledge of thermodynamic properties of minerals under high temperature (150 to 200°C), high pressure (1000 to 1500 bar), and high total dissolved solids (more than 300,000 mg/L). Scale prediction models are limited by lack of experimental data and inadequate understanding of modeling parameters. With a new apparatus, solubilities of barite and calcite were measured at temperatures up to 250°C, pressures up to 22000 psi, and ionic strength up to 6 m NaCl and in the presence of elevated concentrations of mixed electrolytes representing the nealy maximum range of interferences expected in brine. Preliminary measurement of gypsum solubility under high pressures were also conducted. Based on solubility measurements, the temperature and pressure dependence of stability constants and Pitzer coefficients were validated and adjusted. In addition, specific ion interactions are validated and constructed through solubility measurement in synthetic brine with mixed electrolytes. On these bases, our thermodynamic model was improved and can be applied to scale prediction for barite and calcite under extreme conditions usually encountered in the oil field.
Structure, Stoichiometry, and Modelling of Calcium Phosphonate Scale Inhibitor Complexes for Application in Precipitation Squeeze Processes
Authors: Shaw S. S. , Sorbie K. S.
Published: June 2014

Phosphonate scale inhibitors (SIs) applied in downhole squeeze applications may be retained in the near-well formation through adsorption and/or precipitation mechanisms. In this paper, we focus on the properties of precipitated calcium phosphonate complexes formed by 9 common phosphonate species. The stoichiometry (Ca/P ratios) in various precipitates is established experimentally and the effect of solution pH on the molar ratio of Ca/P in the precipitate is investigated. All static precipitation tests were carried out in distilled water, with only Ca2+ (as CaCl2) and SI present in the system at test temperatures from 20°C to 95°C. The molar ratio of Ca/P in the solid precipitate was determined by assaying for Ca2+ and P in the supernatant liquid under each test condition by ICP spectroscopy (Cao and Po are known, but are also measured experimentally). We show experimentally that the molar ratio of precipitated Ca2+/P (or Ca2+/SI; or n in the SI_Can complex) depends on the SI itself and is a function of pH, for all phosphonates tested. It is found that, as pH increases, the molar ratio of Ca2+/P (n in the SI_Can) in the precipitate increases up to a theoretical maximum, depending on the chemical structure of the phosphonate. Our findings corroborate proposed SI-metal-complex ion structures which were presented previously (Shaw et al., 2012c), as discussed in detail in the paper. In addition, the precipitation behaviour of the various compounds is modelled theoretically by developing and solving a set of simplified equilibrium equations. We find that the precipitation behaviour can be modelled, but only if a fraction, β, of "non-SI" of the initial phosphonate SI is taken into account. The quantity β can be as high as 0.2 (i.e. ~20% non-SI), although there is a degree of variability in this factor from product to product. However, good quantitative agreement is shown comparing the predictions of the equilibrium solubility model with experiment. Such models can be used directly in the modelling of field phosphonate precipitation squeeze treatments.
Experimental Study of Friction Reducer Flows in Microfracture During Slickwater Fracturing
Authors: Sun Yongpeng , Zhang Hao , Wu Qihua , Wei Mingzhen , Bai Baojun , Ma Yinfa
Published: June 2014

Tight formations with extremely low matrix permeabilities, such as gas shale, can produce at economical rates is due to inborn fissures and fractures introduced during hydraulic stimulation. Hydraulic fracturing in gas shale can connect/generate these microfractures, causing them to become much more complex fracture networks. These microfractures have much more contact area with the matrix and therefore hold the majority of the productivity potential of gas shale.

Slickwater fracturing has been proved to be an effective method by which to increase the recovery of shale gas reservoirs. Friction reducer is the primary component of this fluid. It can decrease the flowing friction in macro tubing. Lab tests and field applications have addressed this issue thoroughly. However, the flow characteristics of this solution in microfractures are not clear.

The present study will show how this solution flows in microfractures by employing micro-sized fracture model. FR solution is a shear thinning fluid. Rather than reducing flow friction, with the FR fluid in a 1000 μm height, 50 width μm and 4.14 cm length microfracture, the injection pressure did not decrease but rather increased 36%. The impact of FR solution concentration was found to be more obvious at low velocities. At the same shear rate, the apparent viscosity is higher in large microfractures. At the same velocity, large microfractures have higher residual resistance factors. Through the analysis of fluid emulsion particle size and shale matrix pore size, this FR solution will not go into the matrix pores easily, but can block the pore entrance to prevent the fluid from leak off and to protect the formation from contamination during slickwater fracturing.
Calcium Naphthenate Solid Deposit Identification and Control in Offshore Nigerian Fields
Authors: Oduola Lukman , Igwebueze Clement , Smith Oluwaseun , Vijn P. , Shepherd Andrew G.
Published: June 2014

Two operated fields in offshore West Africa began experiencing aggressive solid deposition challenges soon after the onset of water breakthrough for Field A and Field B. This led to significant process control and flow assurance issues in the crude processing plants. Problems experienced included: plugging of separator bridles, hydrocyclone liners and level control valves, solid loading in overboard water, poor oil-water interface and loss of retention time in separators and plugging of reject lines of the produced water treating vessels.

An extensive solid deposit identification campaign was undertaken in order to establish the composition of the samples. Calcium naphthenate (CaN) scale was identified as the major component in the solids, the first major occurrence experienced in the Gulf of Guinea for the operators of Fields A and B. A competitive screening of CaN inhibitors resulted in the pre- selection of a low dose non-acidic formulation. The CaN inhibitor formulation selected in the laboratory was then trialed in the two offshore fields, according to a well-defined set of key performance indicators (KPIs).

Results from the field trials indicated significant reduction in the solid deposition rate. The flushing of separator sight glasses reduced from three times per shift to once in four days. Hydrocyclone liners and induced gas flotation units opened for inspection following five weeks of treatment showed no significant CaN scale present. Online oil and water filtration exercise showed downward trend in solid deposition across the FPSOs in the systems of both Field A and Field B. Produced water quality was not compromised. The CaN issue is now under control and subject to a surveillance campaign.

This paper showcases an operational excellence approach to solving the CaN problem in the face of increasing solid deposition challenges in offshore operations as seen in the Gulf of Guinea and currently in other parts of the world.
Scale and Scale Inhibition Challenges for an Alkaline Surfactant Polymer Flood in a Seawater Flooded Reservoir
Authors: Alwi Noraliza , Salleh Intan Khalida , Irvine-Fortescue Jamie , Graham Gordon , Dyer Sarah , Wright Rob , Simpson Caroline , Kidd Sam , Stalker Robert
Published: June 2014

Scale control during Alkaline Surfactant Polymer (ASP) flooding is a recognised challenge especially following ASP breakthrough at the production wells, due to continual mixing of the high pH ASP waters with reservoir brine. The effective performance of scale inhibitors (SIs) is a problem, given the high oversaturation expected due to mixing of injected alkali and formation water. Previous work (SPE 141551) described this challenge for a conventional system whereby ASP was injected into a reservoir containing low salinity / low divalent ion Formation Water (FW). This work showed that chemical performance (SI/ brine compatibility and performance) could be achieved using conventional inhibitors and that treatment of the production wells via downhole squeeze treatments was achievable. It also demonstrated that the production of high pH ASP fluids had a considerable impact on the retention and release properties of the chemicals.

This paper progresses significantly from the previous work by examining a field case study. Although the formation water is a low salinity / low divalent cation brine similar to that in the earlier example, this field represents a considerably more severe scaling challenge since it has already been flooded with Sea Water (SW). The SW contains considerably higher divalent cation concentrations (c.f. Ca2+ ~ 450mg/l vs. ~40 mg/l for the formation water) and results in a considerably more severe challenge in terms of SI/Brine compatibility and chemical performance when examining a range of conventional SI's.

The paper describes extensive modeling of the in situ conditions for this field following ASP flooding, extensive scale inhibitor performance tests across a wide range of conditions and mixtures of ASP/FW/SW together with a series of core flood tests to assess the potential for squeeze treatments in this new pilot ASP system.

For the pilot, reservoir modelling was essential to simulate the expected mixture of ASP/FW/SW which would be produced, such that chemicals could be targeted for the expected produced mixtures (Note: increased FW:SW ratio results in more achievable inhibition) allowing chemical selection for squeeze. The pilot ASP flood in this field is now planned for 2014.
Laboratory Studies for Surfactant Flood in Low-Temperature, Low-Salinity Fractured Carbonate Reservoir
Authors: Sagi Aparna Raju , Puerto Maura , Bian Yu , Miller Clarence A. , Hirasaki George J , Salehi Mehdi , Thomas Charles P. , Kwan Jonathan T
Published: June 2014

The objective was to identify surfactants for Enhanced Oil Recovery by brine-oil interfacial tension reduction for a carbonate reservoir at ~ 25°C and salinity of ~11,000ppm TDS; thus, Alkyl Propoxy Sulfates and their blends with sulfonates were evaluated to determine optimal salinity and solubilization parameters with dead crude. Imbibition experiments were performed in reservoir and dolomite outcrop cores to determine the oil recovery efficiency of surfactant systems, selected from their phase behavior test results, with potential to recover oil. Tridecyl alcohol 13 propoxy sulfate (TDS-13A) with an oil solubilization parameter of ~8 at reservoir salinity was found to recover greater than 75% oil in imbibitions experiments, at a concentration as low as 0.5wt%. The adsorption of surfactants on dolomite was measured at static and dynamic conditions; the adosprtion of TDS-13A was found to be ~ 0.26 – 0.34 mg/g reservoir rock. The effect of solution gas on surfactant phase behavior, up to 600-psi, was evaluated for methane, ethane, carbon-dioxide, and separator gas at 30°C. Methane had minimal effect on surfacatant optimal salinity, lowering it by ~2%/100psi solution gas, followed by carbon-dioxide which reduced it by ~11%/100psi. Ethane had a much more pronounced effect, reducing optimal salinity by ~46%/100psi solution gas.
Solids-Free Fluid-Loss Pill for High-Temperature Reservoirs
Authors: Gamage Pubudu , Deville Jay P. , Sherman John
Published: June 2014

The leakage of reservoir fluids into a wellbore during perforation, workover, or other completion operations is a substantial concern, especially in high-temperature wells where existing fluids used to mitigate reservoir-fluid influx offer poor performance. To maintain the hydrostatic integrity of the wellbore during these operations, a thermally stable, solids-free fluid-loss pill has been developed.

The pill is composed of synthetic polymers and crosslinkers in monovalent high-density brine. Under ambient-pressure and -temperature conditions, the pill flows as a viscous liquid and remains fluid for more than 6 months. Upon exposure to elevated temperatures (200 to 375°F), the pill crosslinks to form a robust gel that can act as an appropriately weighted, low-fluid-loss pill. This pill can temporarily seal the reservoir, enabling well control during completion operations.

Gelled samples of the fluid-loss pill have maintained integrity for up to 3 weeks under high-pressure/high-temperature (HP/HT) conditions in laboratory testing, with minimal signs of collapse. The gel can be readily destroyed with an oxidative breaker providing a substantial reduction in viscosity. At the end of the completion process, the timing of gel removal is completely controlled by the timing of the breaker addition.

In addition to gel-stability tests, formation damage caused by the gel and the fluid loss of the pill were assessed by coreflooding experiments by use of Berea core plugs. Average fluid loss over 3 days at 320°F was approximately 50 cm3. Restoration of the Berea core permeability after the treatment exceeded 85% of the initial permeability, with low lift-off pressures observed. This paper presents full laboratory data on the development of the thermally stable, solids-free fluid-loss pill, including gel-stability, fluid-loss, and breaker testing.
The Influence of Turbulence or Hydrodynamic Effects on Barium Sulphate Scale Formation and Inhibitor Performance
Authors: Sutherland Louise , Johnston Clare , Taylor William
Published: June 2014

Inorganic scale (carbonate, sulphate and sulphides) formation can be predicted from thermodynamic models and over recent years better kinetic data has improved the prediction of such scales in field conditions. However these models have not been able to predict the observed deposition where flow disturbances occur, such as at chokes, tubing joints, gas lift valves and safety valves. This can lead to unexpected failures of critical equipment such as downhole safety valves (DHSV's), and operational issues such as failure to access the well for coiled tubing operations due to tubing restrictions.

In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that increased turbulence also impacts the minimum scale inhibitor concentration required to prevent scale.

One of the industry standard test methods used to screen inhibitors for barium sulphate inhibition is the static bottle test. In this paper the ‘static’ bottle test method is modified to investigate the effects of increasing levels of turbulence on the formation of barium sulphate scale at two different temperatures and therefore different supersaturations for a fixed brine composition. Using this modified method it has been possible to demonstrate the impact of varying turbulence on the performance of two common generic types of scale inhibitor (phosphonate and vinyl sulphonate co-polymer). Data on the mass of scale formed, scale morphology using SEM imaging and inhibitor efficiency will be linked to degree of turbulence and scale inhibitor functionality (nucleation inhibition vs. crystal growth retardation).

The findings from this study have significant impact on the methods of screening scale inhibitors for field application that should be utilised and development of suitable chemicals that perform better under higher shear conditions.
Novel Associative Acrylamide-based Polymers for Proppant Transport in Hydraulic Fracturing Fluids
Authors: Gaillard N. , Thomas A. , Favero C.
Published: June 2014

The properties of novel polymers for proppant transport in hydraulic fracturing operations are discussed. Acrylamide based associative polymers have been synthesized using various industrial production processes. Anionic polymers investigated are acrylamide (AMD) based co- and ter-polymers functionalized with monomers such as sodium acrylate (AA), sodium acrylamido-tertiary-butyl sulfonate (ATBS) and a home-made surfactant monomer. The rheological properties of the developed polymers in different brines are evaluated and compared to commercial guar gums usually used for fracturing fluids. The viscoelastic properties as well as settling time of proppant in graduated cylinder have been evaluated. The impact of oxidizing breakers and surfactants added to increase or decrease the viscosity of solutions are reported as well. The new polymers can be used in slickwater, linear gel and cross-linked hydraulic fracturing fluid. They have the ability to carry the proppant down to the target zone. With this technology, proppant can be transported and placed into the fractures with lower concentrations of product and reduce or eliminate the need for using guar gum. Fluid viscosity can be controlled (either increased or decreased) by the addition of surfactants and broken by conventional oxidizers. Laboratory data shows that new associative polymers solutions give very high viscosity at low shear rate and a strong reversible shear thinning effect. Typically, for 3000 ppm of associative polymer, settling time of proppant is 10 times longer than for the same concentration of guar gum. In gel-based fracturing jobs, transport of proppant is generally achieved using guar gum whose viscosity may be improved by adding cross-linkers such as borate or zirconium. The polymer presented in this paper could be a total or partial alternative to guar for proppant transport whose price is subjected to harvest aleas. Results show that lower polymer concentrations are required to obtain the same or even better suspending properties. Besides, traditional oxidizing breakers could be replaced by surfactant to decrease the viscosity of the fluid once the proppant has been placed in the fractures.
The Application of Nanoparticle-Stabilized CO Foam for Oil Recovery
Authors: Yu Jianjia , Mo Di , Liu Ning , Lee Robert
Published: June 2014

This paper presents a process for CO2 foam generation in the presence of nanosilica particles as supercritical CO2 and nanosilica dispersion flow through a sandstone core at reservoir conditions of 20°C and 1,200 psig. The generation of CO2 foam was observed in an online sapphire tube. Pressure drop across the core was measured to estimate the fluid mobility and foam resistance factor. Foam mobility and particle retention were investigated and core permeability after the CO2/nanosilica dispersion flooding was also measured to determine the particle plugging in the core. The application of the nanoparticle-stabilized CO2 foam for waterfloods residual oil recovery from sandstone cores was investigated. The results indicated that nanoparticle-stabilized CO2 foam could improve oil recovery after waterfloods in both low and high permeability cores. The total oil recovery by CO2 and nanosilica flood was 48.7% from the core with permeability of 33 md and 35.8% from the core with permeability of 270 md under the pressure of 1,200 psig.
Laboratory Development of A Novel, Non-Triazine-based Hydrogen Sulfide Scavenger and Field Implementation in the Haynesville Shale
Authors: Chaudhry F. , Mobley G. L. , Tsang Y. H. , Ramachandran S. , Jovancicevic V. , Braman S. C. , Rowton E. N. , McDonald A. P. , Davis J. A
Published: June 2014

Hydrogen sulfide (H2S) is found in many shale gas fields. It is important to remove the H2S to allow for safe transport of the produced gas and to reduce corrosion concerns. The H2S concentration present in the gas is typically low enough that it becomes uneconomical to utilize a regenerative facility such as an amine plant. For this reason, liquid H2S scavengers are the most common mitigation strategy, with nitrogen-based triazines being the most commonly utilized scavenging chemistry. Hydrogen sulfide scavengers can be introduced by direct injection2 into mixed production or separated wet gas pipelines. They can also be reacted with H2S in scavenger flooded contact towers. Applications utilizing towers consume less H2S scavenger; however, the use of contact towers introduces additional capital costs in the operation. Often when high pH, triazine-based H2S scavengers are used, calcium carbonate scale deposition can occur because of neutral pH brine, requiring the facility to be shut in and treated with mineral acids. The reaction product of triazine with H2S can be difficult to dispose of, which increases facility operating costs (e.g. separate disposal tanks and dedicated disposal wells for spent scavenger).

A novel, fast-acting, non-triazine based H2S scavenger has been developed. This new H2S scavenger reacts quicker and has better efficiency than other non-nitrogenous based scavengers (e.g. glyoxal). The neutral pH of the new product eliminates the concern for calcium carbonate deposition that is often experienced with triazine-based scavengers. The new scavenger has been tested for thermal stability and compatibility with other production chemicals. The product has the ability to partition in oil and water phases, making it a more versatile scavenger. Finally, the new product has a better environmental profile than other commonly used H2S scavenger chemistries.

A field trial was conducted using the new non-triazine H2S scavenger. The trial included direct injection into mixed production and separated wet gas lines. Innovative engineering solutions were devised to apply the new H2S scavenger. The combination of the novel application methodology, with the new H2S scavenger chemistry, resulted in a more cost-effective means of treating sour shale gas than is currently achieved with conventional triazine-based H2S scavengers utilizing contact tower applications.
Synthesis and Sorption Study of AlOOH Nanoparticle Cross-Linked Polymeric Scale Inhibitors and their Squeeze Performance in Porous Media
Authors: Yan Chao , Kan Amy T. , Wang Wei , Yan Fei , Wang Lu , Tomson Mason B.
Published: June 2014

Polymeric scale inhibitors are widely utilized in the oil and gas field because of their enhanced thermal stability and better environmental compatibility. However, the squeeze efficiency of such threshold inhibitors, not only polymeric scale inhibitors but also phosphonates, is typically poor in conventional squeeze treatment. In this research, nanoparticle cross-linked polymeric scale inhibitors were developed for scale control. Nearly monodispersed boehmite (γ-A1O(OH)) nanoparticles (NPs) with average size of 2.8 nm were synthesized and used to cross-link sulphonated polycarboxylic acid (SPCA). Cross-linked AlOOH-SPCA nanoinhibitors were produced and developed to increase the retention of SPCA in formations by converting liquid phase polymeric scale inhibitors into a viscous gel. Sorption study of SPCA onto AlOOH NPs under different pHs with and without assistance of Ca2+ was discussed. In addition, sorption study of various types of scale inhibitors (SPCA, PPCA and DTPMP) onto AlOOH NPs was also performed. Squeeze simulation of neat 3% SPCA, AlOOH(3%)-SPCA(3%) NPs and AlOOH(3%)-SPCA(3%)-Ca NPs were investigated. The results showed that the addition of Ca2+ ions improve the squeeze performance of SPCA and the normalized squeeze life of such material (8,952 bbl/Kg) was improved more than 60 times compared to that of SPCA alone (152 bbl/Kg).
Identification of Sustainable Chemistries for Microbial Control in a Deep Offshore Waterflood
Authors: Sianawati E. , McGinley H. , Yin B. , Prisco A. , Lévy R.
Published: June 2014

Microbial control products for offshore production facilities need to meet stringent product specifications and performance criteria, and must be compatible with infrastructure such as pump capacity and materials of construction. This paper describes the biocide selection process and recommendation for an offshore operation in West Africa.

The chosen chemistries needed to demonstrate robust microbial control under field conditions for top side and downhole protection, as well as pipeline protection. Product specifications such as good chemical stability above 60°C, high flash point, low viscosity, non-corrosive, and low foaming potential also needed to be met. Additional constraints included a defined treatment protocol, and a request that both a glutaraldehyde (GDA) -based product and a tetrakis (hydroxymethyl) phosphonium sulfate (THPS)-based product be recommended.

A wide range of GDA and THPS-based products were tested against planktonic halophilic sulfate reducing bacteria (SRB's) using high throughput testing. No differentiation between products was observed under these conditions. More sophisticated test methods that evaluate kill of sessile bacteria again, showed little differentiation in the short term, but when longer-term control of biofilm regrowth was considered, two GDA formulations performed well. One was ruled out due to its high foaming potential. The leading GDA based formulation (GDA 4) and a non-foaming THPS-based formulation which also met efficacy requirements (THPS B) were further evaluated under conditions simulating microbial corrosion in a pipeline. Both mitigated corrosion relative to an untreated control as indicated by electrochemical monitoring. Corrosivity of the products towards common materials in saltwater was also considered. For Duplex 2205 and stainless steel, no significant corrosion was observed for either neat or use-concentration product. For carbon steel, THPS B showed little variation from the saltwater control while GDA 4 gave marginal protection relative to saltwater alone. Therefore both products were found to suit the requirements of the operation.

This study shows the importance of a holistic approach to microbial control beyond standard planktonic efficacy testing. The selection process should include not only efficacy against relevant microorganisms and conditions, but also evaluation of chemical and physical properties of the product.
Application of Quantitative Structure-Property Relationship (QSPR) Method for Chemical EOR Surfactant Selection
Authors: Moreau Patrick , Oukhemanou F. , Maldonado A. , Creton B.
Published: June 2014

The selection of high performance surfactants for chemical EOR is a challenging and time consuming task. A surfactant formulation, typically a blend of at least two surfactants must be developed for each case study. A tool to pre-select suitable surfactants would thus be highly valuable. In this paper, we describe the development of a quantitative structure-property relationship applied to the selection of surfactants for chemical enhanced oil recovery. A correlation is drawn between surfactant structures and optimal salinities, i.e. the salinity which corresponds to a minimum in interfacial tension.

A comprehensive and coherent database has been generated using a high-throughput screening robotic platform and industrial products belonging to different families of surfactants: olefin sulfonates, alkyl ether sulfates and alkyl glyceryl ether sulfonates. This database has been built for specific reference conditions (temperature, oil, brine hardness). Industrial surfactants, most often constituted of a variety of molecules, have been carefully analyzed in order to identify predominant species. The structures of these compounds have then been drawn using molecular design tools, and molecular descriptors were generated for the whole set of amphiphiles. Finally, various statistical approaches have been used to develop multi-linear regressions correlating combinations of the most relevant molecular descriptors with the experimentally determined optimal salinity of surfactant mixtures.

Our results indicate that a strong correlation exists between the surfactant structure and its optimal salinity. A limited set of descriptors can be used to predict this critical property with predictive models. These models can then be used to select promising existing products as well as to identify candidate raw materials or products for industrial surfactants development. We also demonstrate the ability of our models to predict optimal salinity of surfactant blends typically used in chemical EOR.

Future developments will be focused on extrapolation of these models to the prediction of other application properties for chemical EOR (e.g. interfacial tension value) and to broaden the application domain to a wide range of conditions (temperature, brine composition, type of oil).
Shale Drilling: The Impact of Shale Chemo-Physical Constituents on the Issue of Poor Drilling Performance at Depth
Authors: Hayatdavoudi A. , Nasab Y. Sardooee , Mensa-Wilmot G. , Hover V. , Boukadi F.
Published: June 2014

New energy demands are pushing the petroleum industry to drill more shale formations. At the same time, the shale slow drilling rate at depth convinces us that there is a need for serious attention to this field, namely finding a way first to understand the causality and then to resolve the bit balling issue associated with slow shale drilling. For this reason the industry has always been interested in finding viable solutions to mitigate "bit balling" as a main source of shale slow drilling rate. In this work we try by various means to understand the shale slow drilling issues.

Rosebank is one such field located in the west of Shetland, North Sea. This field encounters slow drilling rate at great depths. The authors studied the aforementioned field to investigate different shale chemo-physical parameters affecting drilling rate and most importantly, those which adversely affect drilling performance. These parameters comprise (1) shale chemo-physical constituents and (2) operational drilling parameters. For finding a cause and effect relationship between (1) and (2) and characterizing the shale we carried out extensive Elemental Oxide analysis using Energy Dispersive Xray (EDX), Xray Diffraction (XRD) to identify and understand relationship between the shale-clays structural formula Non Performance Factor intervals. What guided us to these relationships were the chemical reasons for shale Water Retention which addresses part (1) and devise a theoretically sound model (HDPP) to pinpoint troublesome shale sections and for addressing the shale slow drilling issue in part (2) above.

The results show a clear cause and effect relationship between (1) the shale chemo-physical constituents and (2) poor shale drilling at depth where the bit records indicate inefficient Drilling Performance Parameter. Specifically, we have pinpointed the depth where the increase in the shale Iron and Water content match the onset of poor drilling and the necessary sidetracking the well for the prospect under study. We concluded that shale water retention is due to the hydration property of Iron and Sodium especially when the ratio of Iron / Sodium becomes very high. This high ratio is also found where the ratio of Smectite / Illite and the shale water content is high as well. Obviously these high values do not permit the shale to completely expel water under the Compaction- Consolidation stresses at depth and that shale water retention renders it plastic, bit-balling shale. The benefit our work to industry is imbedded in our trouble shooting methodology for this particular prospect. Specifically, assuming all mud plan and treatments and the choices of selecting drilling parameters are made properly, we recommend the Iron control additives be a part of mud formulation for this prospect to mitigate further activation of shale stickiness and balling effect.
Methodological Approach for Analyzing the Impact of Chemical EOR on Surface Processes
Authors: Argillier J-F. , Dalmazzone C. , Henaut I. , Mouazen M. , Noik C. , Boufarguine M.
Published: June 2014

One important aspect that is generally neglected in chemically-based enhanced recovery technology concerns the impact of the EOR chemicals on the produced water cycle. After the chemical breakthrough, part of the EOR chemicals will be recovered in the produced fluids and may strongly impact oil/water separation and water treatment surface processes.

This paper describes a specific laboratory methodology designed to study the impact of ASP-type chemicals on produced fluids treatment efficiency and will highlight the impact of polymers and sulfonated EOR surfactants on oil/water separation and water treatment efficiency. The methodology consists in a first step in evaluating the risk of stable emulsion formation and assessing the impact of chemical EOR on separation efficiency. Produced fluids are formulated and characterized (different water cuts, type of agitation, EOR chemicals,…). The stability of the different emulsified systems is analyzed over time. Then the efficiency of separation of water-in-oil (w/o) emulsions is determined for the three main types of dehydration processes: gravity separation, chemical demulsification, electrical dehydration. The quality of the separated water is systematically reported. In a second step, impact of chemical EOR on produced water treatment efficiency is studied. Produced waters are formulated and characterized (different oil concentrations, simulated back produced EOR chemicals,…). Behavior of theses systems are then studied using here an induced gas flotation lab column and membrane filtration. Turbidity of the water and concentration of oil in water is monitored as a function of time to quantify the impact of the EOR chemicals on treatment efficiency. This methodology will be illustrated on a heavy oil in presence of EOR chemicals (HPAM, sulfonated surfactants). The results show that these chemicals can have a strong impact on surface processes. This work emphasises that water management is an important challenge for chemical EOR that needs an integrated approach and should be studied upfront.
An Evaluation of the Significance of Permeability Measurements
Authors: Warren J.E. , Skiba F.F. , Price H.S.
Published: June 2014

A technique for comparing core-analysis permeabilities to those determined from pressure build-up tests has been developed. This comparison has been used to obtain a qualitative indication of the spatial permeability distribution within the producing formation. Data from 14 wells, equally divided between the Bromide sands and the McKnight dolomite, have been analyzed; results have indicated that the permeabilities in those particular reservoirs are randomly arranged so that they appear to be homogeneously heterogeneous. It has been emphasized that more accurate core data, improved pressure build-up testing and independent determinations of anisotropy are needed before a more quantitative description of the reservoir is feasible.

Introduction

The purpose of this paper is to compare permeabilities determined by core analysis with those calculated from pressure build-up data. Since a single value for the effective permeability of the drainage area is obtained from a build-up test, it is necessary that the core analysis values be averaged in some manner to allow the comparison to be made. If an averaging method that reconciles the core and build-up permeabilities can be found, it is possible to infer, in a qualitative sense, the spatial distribution of permeabilities that exists in the reservoir. Since the suggested approach gives a gross indication of the type of reservoir heterogeneity that is based on a comparison, the inherent errors in the raw data must be carefully considered.

Recent experimental and theoretical research on the nature of recovery mechanisms, developments in the field of numerical analysis and the evolution of truly high-speed digital computers have made it possible to predict the performance of virtually any reservoir that can be adequately described. Unfortunately, the necessary condition that demands an adequate description of the formation cannot be satisfied in general. As a result, the usefulness of the available numerical models is seriously impaired.
A Visual Journey Into the 3D Chemical Nanostructure of Oilwell Cement
Authors: Torsæter Malin , Opedal Nils , Vrålstad Torbjørn , Vullum Per Erik
Published: June 2014

To enable efficient design of oilwell cements that can be placed with precision and that can withstand the harsh conditions often encountered downhole, it is important to understand how these materials are built up at smaller length scales. Since cement pores and grains can be of micro- or even nano-meter sizes, and since they are connected in space, detailed cement characterization requires advanced experimental techniques of good resolution that can provide three-dimensional (3D) information.

In the present paper we demonstrate how the nano- and micro-structure in the interior of set cement samples can be studied by using a Focused Ion Beam - Scanning Electron Microscope (FIB-SEM). This instrument performs nano-tomography, allowing small 3D cement volumes to be digitalized. In this way, chemical mapping of element distributions within the solid cement phases can be performed, and the 3D pore network can be reconstructed in great detail. This makes FIB-SEM an ideal experimental technique for investigating e.g. cement porosity, chemical attack on cements, cement-formation (de)bonding and structural or chemical effects of additives. The final output of FIB-SEM experiments, being digitalized microstructural features like grains or pores, can be used as input for numerical modeling schemes.

The FIB-SEM experiments presented in this paper demonstrate how this technique can reveal subtle microstructural differences in two Portland G cement samples mixed with water-to-cement ratios varying within the range that is typically used for well cementing. These distinctions are shown to be complementary to the larger-scale differences observed within the same samples when analyzing them with micro computed tomography (μ-CT). It is shown how the spatial extent of the internal pore network and the pore sizes are dependent on the water-to-cement ratio. We also show, through various mechanical testing procedures, how this multi-scale cement porosity affects the macroscopic properties of the material.
Scale Prediction for Iron, Zinc and Lead Sulphides and Its Relation to Scale Test Design
Authors: Okocha C. , Sorbie K.
Published: June 2014

The accurate prediction and management of oilfield sulphide scales, such as iron sulphide, is an important issue in oil production. This has become particularly significant as high temperature high pressure (HTHP) fields are being brought into production, and the life of mature fields is being extended. In such systems, additional scales such zinc and lead sulphide (ZnS and PbS) are often being reported.

This paper presents a detailed description of a sulphide modelling approach, leading to the prediction of saturation ratios (SRs) and masses of the formed sulphide scales, final solution compositions, final pH levels etc. The equilibrium equations for the sulphide system are presented and solved in a manner in which they are compared directly with the experimentally measured quantities. The actual Saturation Ratios (SRs) (e.g. SR = [Fe2+][S2-]/Ksp,FeS) are calculated for the various experiments and the prediction model is used directly to the design the details of the sulphide scaling experiment in the blank solutions.

Some calculated sulphide examples are presented and some key predictions of the sulphide scaling model are tested experimentally for FeS, ZnS and PbS systems. The quantitative agreement between the predictions of the model and the experiments are very good. The resulting sulphide test methodology is thus well underpinned theoretically and it is then applied to evaluate some examples of proposed commercial sulphide inhibitors/dispersants.