Oilfield Conditions Research Articles

Formation of Corrosion‐Resistant Thermal Diffusion Boride Coatings

The corrosion related issues in oil production can be significantly reduced using the coatings based on the compounds from the metals of the IVb–VIb and VIII groups and the non‐metallic elements of the IIIa–Va groups with strong covalent bonds and high thermodynamic potentials. Iron boride‐based coatings with consolidated structures are successfully applied through the thermal diffusion process to protect large production components from steels and ferrous alloys. The principles of the thermal diffusion coating formation are reported. The Fe‐B‐based coatings successfully withstand high temperature – high pressure water steam contained H2S, CO + CO2, hydrocarbons, chlorides in simulating oil field conditions tested in the autoclave and in the pressurized Atlas cell, and in strong acidic environments.

Post-fracturing treatments design to redress the damage caused by fracturing fluid polymers

Seven chemical products with different chemical properties were evaluated as post-fracturing treatments to remove the polymer retained in the pore system of the fracture and adjacent rock after hydraulic fracturing. Three of those chemical products were used for the first time to degrade the polymer in fracturing fluids. All laboratory tests were conducted under the Unit K-1 Chichimene oil-field conditions - located in Eastern Colombia, and operated by Ecopetrol S.A. Fluid-fluid and fluid-rock compatibility tests were performed. In order to evaluate the capacity of the post-fracturing treatments to degrade the polymer in the fracturing fluid, a new methodology for polymer quantification was implemented. The chemical and thermal stability of the post-fracturing treatments was assessed trough coreflooding experiments. Finally, the evaluations of the effectiveness of the post-fracturing treatments were performed and assessed with coreflooding experiments using fractured rocks as porous media. The coreflooding results showed that the post-fracturing treatments evaluated promoted the recovery of about 40% of the total polymer retained in the porous system, and improved the retained permeability in values between 50 and 180%. The best obtained results came from the first-time usage of chemical products as post-fracturing treatments.

Plugging behavior of gellan in porous saline media

ABSTRACTIn this article, the hydrodynamic behavior of dilute aqueous solutions of a natural polysaccharide—gellan in the porous media under the modeled oilfield conditions is described. The hydrodynamic properties of gellan and poly(acrylamide) solutions in saline porous media are compared. The influence of inorganic salts NaCl, KCl, CaCl2, MgCl2, and BaСl2 on sol–gel and gel–sol transitions of dilute gellan solutions was evaluated. The mechanism of sol–gel transition in the presence of individual alkaline and alkaline‐earth metal salts is described on the basis of literature data. The viscometric measurements revealed that the effectiveness of salts to enhance gelation of gellan changes in the following order: BaСl2 > CaCl2 ≈ MgCl2 > KCl > NaCl. The sol–gel and gel–sol phase transitions of gellan solution were also observed upon addition of oil field water containing 73 g L−1 of alkaline and alkaline earth metal ions. During the injection of gellan solutions into the porous media saturated by saline water an oscillation of the injection pressure was observed. Such behavior of gellan is explained by either the sol‐to‐gel and the gel‐to‐sol transitions of the polymer taking place in saline water or the step‐by‐step plugging of high permeable channels until all high permeable channels of sand packs are plugged due to gellan invasion. The application of brine‐initiated gelation of gellan for water shutoff operations (WSO) in field conditions was demonstrated. Higher technological effectiveness of gellan injection in comparison with existing gelation systems was shown. © 2014 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2015, 132, 41256.

Engineering Aspects in the Design and Implementation of Onshore Smart Oil Fields

Summary The smart-field concept is deployed through disseminating elements of toolsand infrastructure integrated to bring a level of smartness that can improvethe performance of an oilfield asset in a sustainable way. The design andimplementation of these tools and infrastructure's underpinning smartness candiffer on the basis of oilfield conditions. Greenfields, for example, can beengineered upfront to leverage all tools and deliver smart-field value from thebeginning of the asset's life. On the other hand, smart-field tools andinfrastructure for brownfields would be designed selectively and be implementedon the basis of several engineering and economic considerations. The main functionalities of onshore smart field are remote operation,real-time information, and collaboration realized by the following tools andinfrastructure: Subsurface permanent downhole gauges (PDHGs) Subsurface flow controls Wellhead instrumentation Telecommunications infrastructure Supervisory control and data acquisition (SCADA) and control system Field-to-headquarters (HQ) connectivity Collaboration work environment (CWE) This paper outlines the engineering aspects to be considered in theselection, design, and implementation of tools and infrastructure for onshoresmart fields.

The pilot study for waste oil removal from oilfields by Acinetobacter johnsonii using a specialized batch bioreactor

The batch bioreactor with a maximum capacity of 0.28 m3 was designed and manufactured according to oilfield conditions Acinetobacter johnsonii ioslated from waste oil in an aerobic environment was employed to cleanse waste oil and wash-down water using the bioreactor in a pilot scale. The aerating process was optimized from 2 to 4 m3/h corresponding to the different cell growth phases, ensuring sufficient dissolved oxygen and avoiding cell damage from the shearing forces due to strong aeration. The bio-treatment of waste oil underwent two stages:one was the wettability reversal of inorganic admixtures from oil phase into waster phase through enlarged wetting angles, and the other was the bio-flocculation in waster phase by intermediate metabolites excreted by cells. Finally, inorganic admixtures were effectively removed from waste oil and wash-down water at the optimal conditions, with the content less than 0.5% in oil phase and turbidity and sulfide less than 100 NTU and 1 mg/L in the water phase, respectively. Such bio-treatment made the oil-water interface clear against oil and water emulsification and in favor of smooth reclamations for waste oil and wash-down water.

Prognostication of the anticorrosive activity in the series of pentenylarylamines and their industrial introduction

Quantum-chemical parameters and regression analysis were used to predict and synthesize a number of compounds with the highest inhibiting activity in the series of pentenylarylamines. For the compounds with the highest inhibiting activity, tri-2,4,6-(1′-methyl-2′-butenyl)aniline and di-2,6-(1′-methyl-2′-butenyl)-4-methylaniline, technical documentation was developed and their inhibiting activity in media as close as possible to real oilfield conditions were performed. On the basis of results of these tests, the given compounds are recommended for pilot tests.

Design and Manufacture of Swell Packers: Influence of Material Behavior

In all well completions (oil and gas fields), effective cement job is necessary for zonal isolation. Failure of cement annulus because of large stresses has been reported in various studies, requiring huge costs in remedial intervention. Swellable packers have emerged as a new manufacturing equipment/technique able to replace conventional cement completion. These packers are custom-manufactured by vulcanizing specially developed swelling elastomer elements onto petroleum pipes. Especially designed and manufactured to suit a particular set of downhole conditions, swell packers are being used in a variety of petroleum applications such as zonal isolation and water shutoff in fractured reservoirs, slimming down of oil wells through replacement of conventional cementing, sand screening, reservoir compartmentalization, etc. Performance analysis and seal design improvement is not possible without reliable information about material response of swelling elastomers. This article summarizes the results of a series of tests performed to determine the swelling behavior of a water-swelling and an oil-swelling elastomer, with and without acid induction. Experimental setup was designed in consultation with petroleum and rubber engineers. Volume, thickness, and hardness of elastomer samples were measured before swelling and periodically after swelling over a one-month period. Test conditions were chosen to replicate actual oilfield conditions.

Mapping erosion–corrosion of carbon steel in oil–water solutions: Effects of velocity and applied potential

In this study, the erosion–corrosion performance of carbon steel was investigated in crude oil, reservoir water, and a mixture of both solutions at a range of applied potentials, velocities and impact angle. The application of such work is to upstream and downstream oilfield conditions, where the proportions of hydrocarbon and water may vary during the extraction process over time. Following exposure of the carbon steel in the crude oil, the extent of erosion was greater than that of corrosion, whilst in the reservoir water, the erosion and corrosion contributions were similar. Regimes of erosion–corrosion were proposed based on the variation in erosion behaviour at various impact angles and applied potentials in the environments studied. Mechanistic changes were identified on erosion–corrosion maps as a function of velocity and applied potential at various impact angles, indicating important transitions in erosion–corrosion processes in the oil/water environments.

Investigation of Application Conditions of Barium/Strontium Scale Inhibitor in Oilfields

In response to the serious barium / strontium – scale in oilfields, we simulated oilfield conditions and investigated the scale inhibition performance of several common scale inhibitors to barium and strontium, by following the protocol from Evaluation Methods of Anti-Scale Agent for Oilfield Use, Petroleum Gas Standards of People’s Republic of China SY/T 5673. The most effective scale inhibitor CD-1 was screened out. With CD-1 as barium / strontium scale inhibitor in the static anti-scale analytical experiments, the dependence of scale inhibition performance on scale inhibitor concentration, saltiness, temperature, time and the system pH was investigated. The application conditions of barium / strontium scale inhibitor in real petroleum and gas field was obtained. Under the optimized application conditions, the mixture scale inhibitor had better scale inhibition efficiency than CD-1 alone.

Versatile Swellable Packer Tool Provides Reliable and Economical Zonal Isolation

Technology Update A simple observation of the expansion of a child's toy snake in water by a lateral-thinking Shell R&D technologist a few years ago has led to an emerging revolution in the oil and gas industry—swellable-elastomer packers. Following rapid industry acceptance, the technology now can be found downhole in wells in every producing region of the world, and the technology recently won a major international award for applied innovation. Versatile, Highly Reliable Technology The underlying objective of using swellable-elastomer packers, most of the time, is to reduce water production and increase oil and gas production proportionally. Swellable packers combine the advantages of mechanical and inflatable packers, without the inherent complications associated with the traditional technologies. Swellable packers adhere to the profile of the formation in a reliable and efficient manner, and like conventional packers, they create a pressure-holding seal within the wellbore. However, unlike traditional methods of zonal isolation, swellable packers always have something in reserve in the event of a future washout or water break-through. In such cases, the packer will swell further and adapt to the new structure until a seal is re-established (Fig. 1). The packers themselves are thin sections of swellable rubber that are vulcanized directly on to standard tubing. The rubber swells when it comes into contact with the appropriate fluid, water or oil. The basic principle is natural and very simple. Add water or oil to an appropriate rubber-based compound, and it will swell as it absorbs the liquid. There are no moving parts to fail, and as long as the application is correctly engineered and deployed, there is very little that can go wrong. However, the key factor is engineering it properly in the first place. The simplicity of swellables belies the science and vast body of research behind the technology. Literally thousands of tests have been conducted on a multitude of compounds, under different oilfield conditions, to make sure that the swellable elastomers will perform exactly as they should downhole. Swellable packers are not a one-type-fits-all technology. Elastomer compounds numbering in the hundreds are needed to meet a vast range of downhole requirements. An exhaustive testing program by Swellfix has found that various characteristics of particular crudes, different oil/water mixtures, and other specific well factors all affect how various swellable compounds perform. A comprehensive understanding of the relationship between packer composition, well fluids, and swelling enables selection of the appropriate compounds for best performance. In 5,000 swellable-packer deployments by Swellfix, no failures have yet resulted. Water- and Oil-Swellable Packers Water-swellable elastomers work on the principle of osmosis, a process that encourages the movement of water particles across a semipermeable membrane, where there is a salinity difference on either side of the membrane. Effectively, the water is drawn into the elastomer and retained because of the salinity gradient across the surface of the elastomer. This causes it to swell, increasing its size to fill a void.

The Use of Finite-Element-Calculated Magnetic-Flux-Leakage Signals To Study the Characterization of Defects in Steel Coiled Tubing

Summary A primary consideration with coiled tubing (CT) is that it is consumed by fatigue loading during routine operations. Also, rugged oilfield conditions routinely lead to corrosion and other mechanical surface damage. Since fatigue is a surface phenomenon, the presence of a surface imperfection has a significant influence on fatigue-damage mechanisms. This paper describes the study of magnetic-flux-leakage (MFL) inspection signals caused by surface defects in the form of milled circumferential grooves in steel CT. The focus of the investigation is to identify and estimate the size of surface defects on the basis of characteristic MFL signal features. It is demonstrated that this effort is greatly enhanced by finite-element analysis (FEA). The ultimate objective is to extract surface-flaw dimensions accurately from conventional MFL signals. These dimensions are used in computer CT life-prediction models. An axisymmetric FEA model is developed and used to calculate leakage flux density solutions for milled circular and rectangular shaped grooves in 1.75-in.-outside-diameter (OD), 0.156-in.-wall-thickness (WT), 90-ksi CT samples. FEA results are compared to axial and radial MFL signals measured with an experimental inspection unit. Favorable agreement is observed between experimental and FEA data. Furthermore, signal features are correlated with the known slot geometries to identify basic geometry-recognition patterns for different circumferential grooves. Signal features reveal qualitative and quantitative trends relative to surface-flaw dimensional characteristics. The need persists to make the operator's string-management decision-making process more reliable and automatic with respect to determining fatigue life expectancy. The obstacle here is that because of the inherent inaccuracies in commonly used MFL inspection techniques, reliable real-time flaw-evaluation and -characterization capability is limited.

Prediction of Scale Formation Problems in Oil Reservoirs and Production Equipment due to Injection of Incompatible Waters

AbstractIn this paper, the mechanisms of scale formation from oilfield water are presented. An accurate model for predicting the scaling phenomena due to mixing of incompatible waters, changes in thermodynamic, kinetic and/or hydrodynamic conditions in oilfield operations is suggested. This model can predict scaling tendency of common oilfield waters in disposal wells, water‐flooding systems and in surface equipment and facilities. The model is developed based on experimental data and empirical correlations, which match the oil field conditions accurately. Furthermore, the simultaneous deposition of different oilfield scales and the competition of various ions to form scale are incorporated in the model. The suggested model has been used to investigate the potential for scale precipitation in various Iranian on‐shore and off‐shore oil fields, where water injection is being performed for the water disposal of desalting units or as a method of secondary recovery or reservoir pressure maintenance.

Measurements of oil–water separation dynamics in primary separation systems using distributed capacitance sensors

This paper provides an overview of research activities conducted and results obtained within an industrially driven research programme managed through UMIST (currently The University of Manchester) over the recent years. Its main objective was to design, construct and demonstrate new instrumentation technologies which could allow reliable measurement of the separation process in the oil and gas extraction industries with the view of transferring the technology developed in academia into the oilfield environment. The paper describes the developments starting from the early work, which aimed at the laboratory qualification of the distributed electrical capacitance sensors embedded in the parallel-plate interceptor of the transparent oil–water separator located at the university Pilot Plant. This is followed by the description of the design, analysis and industrial evaluation of the pre-prototype capacitance probe, containing 24 distributed sensors, in the live oilfield conditions of the BP Exploration facility at Wytch Farm, Dorset, UK. Finally, the most recent advances, including industrial tests of the prototype multi-electrode capacitance probe carried out in the National Engineering Laboratory in Glasgow are reported. The probe was designed and built to include a mechanical deposit prevention system and to meet the flame proof standards of the oil and gas extraction industry. The three case studies presented demonstrate the process of evolution of the measurement technology, which originally stemmed from ECT, and its transfer into the live process environment.

HEC Precipitation at Elevated Temperature: An Unexpected Source of Formation Damage

Summary High-molecular-weight polymers are routinely used to viscosify brines for drilling, workover, and completion operations. Of the commercially available polymers, hydroxyethyl cellulose (HEC) is among the most versatile and widely used products. HEC has been used in NaCl, NaBr, KCl, NH4Cl, CaCl2, and CaBr2 brines over a wide range of brine density, pH environment, and temperature. Typically, the performance issues addressed in HEC studies focus on dispersibility, hydration rate and viscosity development, rheology at elevated temperature, and formation damage. Under typical oilfield conditions, the published data indicate that HEC produces minimum formation damage and provides predictable rheological behavior when properly prepared.

The kinetics of calcite precipitation from a high salinity water

Calcium carbonate is one of the most common and important scale-forming minerals in oilfield produced water, but the kinetics of CaCO 3 precipitation has been ignored in most scale prediction models because of the lack of reliable precipitation rate model. There are none in the open literature for oilfield conditions (temperature > 100°C, pressure > 200 bar and salinity > 0.5 mol kg− 1). In this work the kinetics of calcite (CaCO 3) precipitation from high salinity waters (up to 2 mol kg −1) have been studied by a pH-free-drift method in a closed water system. This method. is much easier to operate than the often used steady-state method. The experimental results indicate that the calcite precipitation rate is not only affected by the solution CaCO 3 saturation level, but also by the solution pH, ionic strength and the concentration ratios of Ca to HCO 3− ions (C Ca 2+ /C HCO 3 − ). When the concentration ratios of Ca to HCO 3 − ions are close to their chemical stoichiometric ratio of 0.5, the calcite growth from a supersaturated solution is believed to be surface reaction controlled. However, at higher C Ca 2+ C HCO 3 − ratios, the transportation of the lattice ions to calcite crystal surface has to be considered.

Part 3: Sulphate and Carbonate Scale Prediction in North Sea Oil and Gas Fields

Abstract Water-borne scales of sulphate and carbonate are major production problem in North Sea oil fields. Scale formation results from two processes: reduction in mineral solubility in produced formation water due to drops in temperature and pressure during production, and chemical incompatibility between formation water and injected seawater. Temperature and pressure drops are chiefly responsible for carbonate scale precipitation. Chemical incompatibility between the reservoir formation water and the injected sea-water is the most common cause of sulphate scaling. Furthermore, the precipitation of one mineral scale may be aggravated or alleviated by competitive co-precipitation of other mineral(s) and specific ion effects. This chapter examines the susceptibility of North Sea formation waters to carbonate and sulphate scale precipitation. Seawater contains a few thousand milligrams per litre (c.2800 mg 1 -1 ) of sulphate anions (SO 2- 4 ), a small amount (c.420 mg 1 -1 ) of calcium ions (Ca 2+ ) and trace amounts of barium (Ba 2+ ) and strontium (Sr 2+ ) ions. In many offshore fields in the northern and central North Sea, the original formation water has trace SO 2- 4 but excessive Ba 2+ and Sr 2+ ions (up to 2000 - 3000 mg 1 -1 ) as well as Ca 2+ ions (up to tens of thousands mg l -1 ). In normal oil field conditions, these two types of brines are usually chemically stable when they are kept apart. However, as seawater is injected into the reservoir formation during a waterflooding process, it commingles with the formation water in various locations of both reservoir and production systems to deposit sulphate mineral scales of barite (BaS0 4 ), celestite (SrS0 4 )

Development and Application of a Fully-coupled Two-dimensional Finite Element Approach to Deformation and Pressure Diffusion Around a Borehole

Abstract The fully-coupled deformation and diffusion behaviour around a boreholedrilled in a fluid-saturated poroelastic medium are modelled using atwo-dimensional finite element method. A variational principle equivalent tothe governing equations in the theory of poroelasticity is derived. Thevariational principle used here to achieve a full coupling is notconventionally employed in porous medium mechanics, therefore verificationprocedures were implemented. The distribution and the history of effective stresses and pore pressurearound the borehole, valuable factors for evaluation of borehole stability andsolids production potential, are evaluated in hydrostatic and non-hydrostaticstress fields, and under different wellbore pressures. For typical cases thatcorrespond to oil field conditions, significant differences are found betweenthe fully-coupled solution and the uncoupled solution. Introduction The basic equations for coupling elastic deformation with pore pressure forporous media subjected to transient fluid flow were first established by Biotin 1941. There have since been numerous restatements given, and Rice and Cleary provide an particularly elegant reformulation of Biot theory byredefining the material constants. The theory of poroelasticity not onlypredicts quantitative differences from uncoupled flow-deformation theory, italso predicts phenomena such as the Mandel-Cryer effect, which are neitherintuitive nor revealed by the uncoupled theories. It has become the preferredapproach in many geomechanical applications, but because of the governingequations' complexity, analytical or closed-form solutions are available onlyfor cases of simple geometry and boundary conditions. For example, a recentdevelopment by Wang and Dusseault provides a solution for fullyporoelastic coupling in an axisymmetric plane strain borehole subjected toinjection or withdrawal. The complexities of the governing equations coupling deformation withdiffusion, combined with the strongly non-linear behaviour of geomaterials, naturally increase the importance and popularity of numerical approaches. The Finite Element Method (FEM) is the most widely used procedure for numericallyapproximating the theory of poroelasticity. In cases involving coupleddeformation-diffusion, there are two formulations of FEM commonly employed tosolve boundary value problems.

Screening Criteria for Enhanced Recovery of Saudi Crude OUs

Abstract The principal objective of this investigation was to study and analyze the screening guides that can be used to select the applicable enhanced oil recovery (EOR) method under Saudi oilfield conditions. Based on the analysis of data obtained from 186 Saudi formations, the crude oils are produced from low to intermediate permeability formations in the range of 1-1500 millidarcies. The original reservoirs' pressure and temperature range from 2000 to 5500 psi and from 140 to 240°F, respectively. The porosity of the formations varies form 10 to 30% and the formations thickness ranges from 10 to 300 feet. The reservoirs of Saudi Arabia are characterized by high formation water salinity, which can be as high as 30% by weight. Saudi oil formations are characterized by connate water in the range of 10-50%. Thus residual oil saturation is expected to be high. The viscosity of most Saudi crude oils ranges from 0.10 to 10 centipoise. The API gravity ranges from 15 to 45 The basic parameters studied include f...

Heater for well deparaffination units

The well deparaffination unit using hot oil should ensure the heating of oil to sufficiently high temperatures (I00-150~ and develop the capacity required for rapid heating of the well to paraffin melting temperature in its maximum deposition zone (300-400 m down the hole). The unit should ensure an injection pressure adequate for processing wells of considerable depth (up to 3000 m) and be mounted on highly mobile transport media. It should function round the year under the oil field conditions~

Development and Field Evaluation of the Production Surveillance Monitor

The production surveillance monitor is an electronic oilwell surveillance tool that responds to the liquid flow rate in a single or two-phase flow stream. This paper describes the operation and the results of laboratory and field testing of the device, which now is ready for use in routine computer surveillance of oilwell performance. Introduction A simple device is needed to estimate or to measure flow in the production line of an oil well. Absolute accuracy is not a major requirement for production surveillance. Errors of +/- 10 percent can be tolerated if an indication of the flow is determined. Because most oilfield production is two-phase flow, the device should indicate the total liquid production of two-phase flow and possibly estimate the total amount of liquid in a single-phase flow. Also, this device must be reliable and rugged, so that it will not fail under oilfield conditions. A simple transducer was developed. Then, the necessary complex analysis was used to monitor the oil wells. Many types of flow meters and flow-measuring techniques were investigated in the laboratory. This paper reports a new flow-measuring plan that met oilfield needs. A dynamic pressure transducer was used to measure small pressure pressure transducer was used to measure small pressure fluctuations that relate directly to liquid flow rate. Prototype Development Prototype Development The phenomena observed in the laboratory indicated a relationship between a crystal pressure transducer measuring dynamic pressure and the flow rate. Dynamic pressure (delta p) is defined in this study as the perturbations pressure (delta p) is defined in this study as the perturbations in the flowline pressure caused by turbulence, valued two to three orders of magnitude less than the static pressure (p) of the line. Fig. 1 shows the difference between dynamic pressure and the flowing line pressure. Eq. 1 relates the dynamic pressure measurement to the velocity in the flowing line: (1) Using Eq. 1, velocity can be determined with a single point measurement. The theory of the relation between point measurement. The theory of the relation between dynamic pressure and velocity is found in the Appendix. A quartz crystal can measure dynamic pressure, but an electronic circuit must convert this measured pressure to the required velocity. The instantaneous variation of pressure shown in Fig. 1 fluctuates with time. Its root pressure shown in Fig. 1 fluctuates with time. Its root mean square (RMS) value also fluctuates widely with time. To reduce these fluctuations and to provide an output that is proportional to velocity, the square root of the RMS signal must be measured and the signal smoothed so that the recorder or computer can follow the flow rate. Fig. 2 contains a schematic of the instrumentalion setup used to measure the dynamic pressure in the laboratory and in limited field tests. The crystal is piezoelectric quartz. The coupler converts the piezoelectric quartz. The coupler converts the highimpedance signal from the quartz crystal to a lowimpedance signal that can be amplified so that its RMS value and square root can be measured. Quartz is suited ideally for this kind of measurement and because of its structure is not subject to distortion by temperature gradients or vibration and shock. In general, it has a linear output and because of its stability, gains in the order of 100,000 may be used. The laboratory prototype tested successfully in more than 20 wells at Shell Oil Co. lead to the development of a model for field use. JPT P. 160