Formation of scale in oilfield pipework has long been a problem. It is also likely that scale might form in the near well-bore region of the reservoir. This thesis examines the simulation of the formation damage possible due to scale, supported by experiments involving mixing brines in sandstone cores. Simulation was performed using a network model to represent the sandstone. The model was "damaged" using precipitation theory and observations on the damage caused to experimental cores. Experiments were performed, using quarried sandstone, to provide data for tuning and matching the model. The experiments used a pressure-tapped core holder to provide more detailed information on the scaling process and a new, two fluid, injection system for better control over mixing of the brines. The experiments demonstrated that permeability loss would be most rapid in the initial stages of scaling. The rate of permeability loss decreased with decreasing supersaturation of the brine mix and Increasing distance from the point of mixing. Characterisation of the permeability decline demonstrated a linear correlation between the damage rate and the initial permeability. Some effects on permeability damage due to morphology of the scale crystals were noted. The crystal morphology was shown to be mainly dependant on the solution composition rather than its supersaturation. Results from the model indicated a great sensitivity to the "poro-perm" characteristics of the network model representing the sandstone. No matching of results to experiments was achieved, but the trends with relation to the permeability change were modelled successfully.

Sulphate scale occurrence is one of the major production problems encountered during waterflooding processes in oilfield developments. In particular, as sea water injection is a common practice in North Sea oil operations, severe production problems are caused by sulphate scale deposition in the production facilities, also concern is arising of the potential formation damage in the near producing well bore zone due to scale precipitation. Of all the scales, barium sulphate precipitation is the most dominant scaling problem in North Sea offshore fields and it is commonly accompanied by strontium sulphate to form barium and strontium sulphate solid solution scale, which has distinct features in terms of scaling crystal morphology, size and hardness. This study was devoted to predict the scaling tendencies of barium sulphate, strontium sulphate and calcium sulphate scales and to investigate the formation damage arising from (Ba,Sr)SO4 scale formation in the porous media. A theoretically consistent model was developed in this study for predicting the sulphate scaling tendencies in single brines or due to mixing incompatible brines, such as seawater and formation water, by calculating the supersaturations and amounts of precipitation of the sulphates at temperatures and pressures covering surface and reservoir conditions. The model is able to predict competitive simultaneous coprecipitation of BaSO4,SrSO4 and CaSO4 of which sulphate is the common ion, reflecting closely the precipitation of more than one sulphate mineral. The scaling tendencies predicted from this model agree well with field observations. The computer programme of the model is compact, optional and user-friendly. The scale prediction model is based on a solubility model which was also developed in this study from the Pitzer equation for electrolyte mean activity coefficient, an approach widely used for calculating properties of aqueous electrolyte solutions because of its sound theoretical basis and accurate representation of electrolyte properties. The predicted sulphate solubilities from the solubility model agree with the published data within the experimental measurement error. Experimental investigation of the (Ba,Sr)SO 4 scale formation was carried out in static bulk solutions and under flow influence in sandstone cores by mixing two incompatible waters. The brines used in the study were both simple artificial brines and full component synthetic North Sea water and formation waters. The rock cores were multi-pressure tapped and the pressure data recorded during the core flow tests were converted to permeability changes. The formation damage due to scaling was examined by studying the rock permeability decline as well as porosity reduction. The scaling crystals and scale distribution within a core were examined by scanning electron microscopy. The experimental results show substantial scale build-up in the cores and large permeability loss resulted from concurrently flowing North Sea water and field waters and from concurrently flowing two incompatible simple brines through cores. The scale nature and permeability damage were largely dependent on sulphate supersaturation and temperature and they were also affected by the change in the ratio between the scaling ion concentrations. The external morphology of the scaling crystals formed from mixing the sea water and formation waters differed significantly from the morphology of those crystals precipitated from the mixed simple brines, suggesting the influence of the presence of the foreign ions other than sodium and chloride ions on scale nature. It is concluded from the study that the scale formation was a rapid process initiated by heterogeneous nucleation and sustained by scaling crystal growth and deposition on the rock pore surface. The sulphate scaling tendency prediction model and the data acquired from the experimental study on formation damage due to barium and strontium sulphate solid solution formation have potential for use in a reservoir simulation model of scale formation.

No description available.

Acid treatment, especially at high temperatures, is very challenging since HCl is really corrosive to the metal equipment. The use of HCl is associated with face dissolution, corrosion, and iron precipitation. Organic acids are weak and less corrosive than HCl but they have a limitation, which means that they can't be used at high concentrations. The next option would be chelating agents. Chelating agents are used in well stimulation, iron control during acidizing, and removal of inorganic scales. Chelates such as ethylenediaminetetraacetic acid (EDTA), N-(hydroxyethyl)-ethylenediaminetetraacetic acid (HEDTA), L- glutamic acid-N, N diacetic acid (GLDA), and nitrilotriacetic acid (NTA) are used in high-pressure/high-temperature oil and gas wells. GLDA is environmentally friendly, which makes it favorable. One of the concerns with these chelates is their thermal stability at high temperatures because if they degrade at high temperatures, they may lose their functionality. This study describes the thermal stability of these chelates, thermal degradation products, and some methods to improve their stability. The thermal stability is determined by measuring the concentration before and after heating using a complexo-metric titration utilizing FeCl₃ as a titrant. The degradation products are identified using Mass Spectrometry (MS). A series of experiments were run in the lab at varying temperatures (300 to 400°F) up to 12 hours, and the results shows chelates are not stable at temperatures greater than 350°F. Furthermore, chelates with two nitrogen atoms are more stable than those with one nitrogen atom. Iminodiacetic acid (IDA), acetic acid, and [alpha]-hydroxy acids are the decomposition products. There is a layer of black deposition after the chelates are heated, which is analyzed using Scanning Electron Microscope (SEM). Some coreflood tests are conducted using these degraded chelates to investigate the effect of these solid precipitates on the permeability of carbonate and sandstone cores. Increasing ionic strength and raising pH results in a higher thermal stability. Some salts such as, NH₄Cl, KCl, Csformate, and NaBr are added to chelate solutions to enhance stability.

According to the Texas Railroad Commission (TRC), ????over 250 billion gallons of produced water is taken out of Texas Soil every year, and more than 35% of this water is not currently fit to use.?? Therefore, it can be assumed that domestically and globally, the petroleum industries challenge has been to develop a high-tech and cost effective method to purify the large volumes of oilfield brines and produced water. Currently, most of the produced water requires several pre- and post- treatment methods to aide in reducing fouling of membranes, separation of components, increasing influent and effluent quality, and preventing unwanted work stoppage during the desalination process. As a result, the pre- and post- treatment conditioning of the produced water affects the economics and scale-up (i.e. residence times, absorption capacity, etc??) of the varying processes parameters. Therefore, this research focuses on developing an economic analysis and determining the adsorption capacity of an organoclay system to remove oil.

Polymers are among the most important of various oilfield chemicals and are used for a variety of applications in the oil and gas industry (OGI) including water and gas shutoff, drilling mud viscosity modification, filtration loss control (FLC), swellable packers, loss circulation material (LCM) pills, enhanced oil recovery (EOR), fracture treatment and cleanup, chemical placement, etc. The deposition and retention of polymer molecules in porous media and their interactions with rock and fluids present complex phenomena that can induce formation damage. Formation damage due to polymer retention can occur via mobility reduction in three possible mechanisms of polymer-induced formation damage: 1) pore-throat blocking, 2) wettability alteration (which can alter permeability), and 3) increase in reservoir fluid viscosity. Physical adsorption can also cause permanent permeability impairment (formation damage). This polymer-induced formation damage (causing a reduction in net oil recovery) continues to be a fundamental problem in the industry owing to the rather shallow understanding of the mechanics of polymer-brine-rock interactions and the polymer-aided formation damage mechanisms. Most models available for polymer risk assessments appear to be utilised for all scenarios with unsatisfying results. For example, only very little, if any, is known on how polymer type, particularly in the presence of brine type impact on formation damage. In order words, one of current industry challenges is finding effective polymers for high salinity environments. Also, the effect of polymer charge, as well as charges at the brine-rock interface are issues that require a deeper understanding in order to address the role polymer play in formation damage. Furthermore, no much recognition has been given to polymer rheological behaviour in complex porous media, etc. The OGI therefore still faces the challenge of the inability to correctly predict hydrolysed polyacrylamide (HPAM) viscosity under shear degradation; and consequently have not been able to meet the need of production predictions. The effect of the above mentioned factors, etc have not been fully integrated into the polymer formation damage modelling. In this PhD research work, theoretical, numerical, laboratory experiments and analytical methods were used to further investigate the mechanics of polymer-brine-rock interactions and establish the mechanisms for formation damage related to polymer application. Three different hydrolysed polyacrylamide (HPAM) products (SNF FP3630 S, 3330 S and FloComb C3525) were used in the experiments; while Xanthan gum was used in the simulation work. The following variables were considered: 1) polymer type, 2) effect of concentration, 3) effect of salinity/hardness, 4) effect of permeability and pore size distributions, 5) effect of inaccessible pore volume (IAPV) on retention, 6) effect of flow rate (where a special method was established to quantify the effect of flow rate on polymer retention). Laboratory rheological and adsorption experiments were designed and conducted. Experimental results indicate that higher concentration of calcium divalent ions in brine help promote polymer retention on rock surface. On the basis of the experimental results, empirical models were developed and validated to: 1) predict HPAM rheological behaviour over a wide range of shear rates, 2) predict salinity-dependent polymer-induced formation damage, 3) in addition, a modified screening model that can aid polymer selection for field application design is proposed. Overall, these models can therefore serve as useful tools, and be used for quick look-ahead prediction and evaluation of polymer related formation damage in oil and gas-bearing formations.

Produced water handling has been an issue of concern for oil and gas producers as it is one of the major factors that cause abandonment of the producing well. The development of effective produced water management strategies poses a big challenge to the oil and gas industry today. The conversion of produced water into irrigation or fresh water provides a cost effective tool to handle excessive amounts of the produced water. In this research we proposed on-site produced water treatment units configured to achieve maximum processing throughput. We studied various advanced separation techniques to remove oil and dissolved solids from the produced water. We selected adsorption as the oil removing technique and Reverse Osmosis (RO) as the dissolved solids removing technique as being the best for our purpose. We performed experiments to evaluate operating parameters for both adsorption and RO units to accomplish maximum removal of oil and dissolved solids from the produced water. We compared the best models fitting the experimental data for both the processes, then analyzed and simulated the performance of integrated produced water treatment which involves adsorption columns and RO units. The experimental results show that the adsorption columns remove more than 90% of the oil and RO units remove more than 95% of total dissolved solids from the produced water. The simulation results show that the proper integration and configuration of adsorption and RO units can provide up to 80% efficiency for a processing throughput of 6-8 gallons per minute of produced water. From an oil and gas producer’s viewpoint output from the produced water treatment system is a revenue generating source. The system is flexible and can be modified for the applications such as rangeland restoration, reservoir recharge and agricultural use.

Understanding the controls on fluid migration in reservoir rocks is becoming evermore important within the petroleum industry as significant hydrocarbon discoveries become less frequent and more emphasis is placed on enhanced oil recovery methods. To fully understand the factors controlling fluid migration in the subsurface, pore scale information is necessary. In this study, synchrotron-based X-ray computed microtomography (CMT) is being utilized to extract physically realistic images of carbonate rock cores for the evaluation of porosity and mineralogy in the Mississippian Midale beds of the Weyburn Oilfield in southeastern Saskatchewan. Non-destructive in-situ imaging by CMT is unique as it provides a detailed and novel approach for the description of pore space geometry, while preserving connectivity and spatial variation of pore-body and pore-throat sizes. Here, three-dimensional micron to sub-micron (0.3ìm-100ìm) resolution of CMT is coupled with, and compared against, conventional laboratory-based methods (liquid and gas permeametry, mercury injection porosimetry, electrical resistivity, backscattered electron (BSE) from electron probe micro-analysis (EPMA) and transmitted light microscopy). Petrophysical and mineralogical information obtained from both CMT and conventional methods will have direct implications for understanding the petrophysical mechanisms that control fluid movement in the subsurface of the Weyburn Oilfield.<p>At Weyburn, CO2 gas is being injected into producing horizons to enhance oil recovery and permanently sequester CO2 gas. Fundamental questions exist regarding: (1) The significance of pore geometry and connectivity to the movement of CO2 and other fluids in the subsurface, (2) the nature of the interactions between CO¬2 and pore lining minerals and their impact on petrophysical properties, and (3) the distribution and mineralogy of finely disseminated silicate and carbonate minerals adjacent to pore spaces as interaction among these phases and CO2 may result in permanent sequestration of CO2. <p>The two producing horizons within the Weyburn Reservoir, the Midale Marly and Midale Vuggy units, have variable porosities and permeabilities. Porosity in the Marly unit ranges from 16% to 38% while permeability ranges from 1mD to greater than 150 mD across the field. For the Vuggy unit, porosity ranges from 8% to 21% with permeability ranging from 0.3mD to 500mD. Using CMT, pore space is critically examined to highlight the controlling factors on permeability. Digital processing of CMT data indicates that pore space in the Marly unit is dominated by intercrystalline pores having diameters of approximately 4 ìm. From here, it is noted that the pore-throat radii are approximately ½ the radii of the pore-bodies, having profound implications to current oil recovery methods. Tortuosity values from CMT are also observed to have similar values in three orthogonal directions indicating an isotropic pore space distribution within the Marly unit. Alternatively, the Vuggy unit is found to possess greater pore-body and pore-throat sizes that are heterogeneous in distribution. Based on this, permeability in the Vuggy unit is strongly dependant on pore-length scales that vary drastically between localities.

Understanding the controls on fluid migration in reservoir rocks is becoming evermore important within the petroleum industry as significant hydrocarbon discoveries become less frequent and more emphasis is placed on enhanced oil recovery methods. To fully understand the factors controlling fluid migration in the subsurface, pore scale information is necessary. In this study, synchrotron-based X-ray computed microtomography (CMT) is being utilized to extract physically realistic images of carbonate rock cores for the evaluation of porosity and mineralogy in the Mississippian Midale beds of the Weyburn Oilfield in southeastern Saskatchewan. Non-destructive in-situ imaging by CMT is unique as it provides a detailed and novel approach for the description of pore space geometry, while preserving connectivity and spatial variation of pore-body and pore-throat sizes. Here, three-dimensional micron to sub-micron (0.3ìm-100ìm) resolution of CMT is coupled with, and compared against, conventional laboratory-based methods (liquid and gas permeametry, mercury injection porosimetry, electrical resistivity, backscattered electron (BSE) from electron probe micro-analysis (EPMA) and transmitted light microscopy). Petrophysical and mineralogical information obtained from both CMT and conventional methods will have direct implications for understanding the petrophysical mechanisms that control fluid movement in the subsurface of the Weyburn Oilfield.<p>At Weyburn, CO2 gas is being injected into producing horizons to enhance oil recovery and permanently sequester CO2 gas. Fundamental questions exist regarding: (1) The significance of pore geometry and connectivity to the movement of CO2 and other fluids in the subsurface, (2) the nature of the interactions between CO¬2 and pore lining minerals and their impact on petrophysical properties, and (3) the distribution and mineralogy of finely disseminated silicate and carbonate minerals adjacent to pore spaces as interaction among these phases and CO2 may result in permanent sequestration of CO2. <p>The two producing horizons within the Weyburn Reservoir, the Midale Marly and Midale Vuggy units, have variable porosities and permeabilities. Porosity in the Marly unit ranges from 16% to 38% while permeability ranges from 1mD to greater than 150 mD across the field. For the Vuggy unit, porosity ranges from 8% to 21% with permeability ranging from 0.3mD to 500mD. Using CMT, pore space is critically examined to highlight the controlling factors on permeability. Digital processing of CMT data indicates that pore space in the Marly unit is dominated by intercrystalline pores having diameters of approximately 4 ìm. From here, it is noted that the pore-throat radii are approximately ½ the radii of the pore-bodies, having profound implications to current oil recovery methods. Tortuosity values from CMT are also observed to have similar values in three orthogonal directions indicating an isotropic pore space distribution within the Marly unit. Alternatively, the Vuggy unit is found to possess greater pore-body and pore-throat sizes that are heterogeneous in distribution. Based on this, permeability in the Vuggy unit is strongly dependant on pore-length scales that vary drastically between localities.

Barium sulfate scaling can cause many oilfield problems leading to loss of well productivity and well abandonment. Currently, diethylene triamine pentaacetic acid (DTPA) is used, along with synergist oxalic acid and potassium hydroxide, to remove the scale by dissolution. However, the chemical factors affecting this reaction are not known fully, leading to mixed results in terms of treatment effectiveness. This thesis investigates the effect of these factors, by analyzing the change in barite dissolution due to intrinsic factors like variations in formulation composition and extrinsic factors like presence of competing ions. The dissolution reaction is carried out, by taking the barite powder and chelant solution in a teflon round bottom flask and measuring the barite dissolved periodically, with an ICP-OES. The effect of different factors is studied by varying each factor individually and plotting the changes in solubilities. These lab tests show that solubility of barite (0.01mM in water), ideally, increases with increasing concentrations of chelating agents, even going as high as 239 mM. However experimental or field constraints lead to significant decrease in dissolution, especially at higher chelant concentrations. Thus, field tests to determine most effective chelant concentrations must precede treatment design. Lab tests also show that combination of DTPA with weaker chelating agents like ethylene diamine tetraacetic acid (EDTA), L-glutamic acid, N,N-diacetic acid (GLDA) or methyl glycine diacetic acid (MGDA) reduces barite dissolution and should be avoided during treatment design. Addition of synergists to the formulations, initially improves dissolution performance, especially for moderate chelant concentrations, but proves detrimental and hence must be avoided, over longer treatments. Finally, presence of competing ions in seawater, calcium sulfate and calcium carbonate, can significantly reduce barite dissolution and must be carefully studied for each formation-fluid system before design of treatments. Thus, this project sets a framework to identify the best chelant formulation and estimate its dissolution profile to ensure, a more informed treatment design for barite scale removal.