Mileva Radonjic

Leakage of CO 2 Through Abandoned Wells: Role of Corrosion of Cement

The potential leakage of CO 2 from a geological storage site through existing wells represents a major concern. An analysis of well distribution in the Viking Formation in the Alberta basin, a mature sedimentary basin representative for North American basins, shows that a CO 2 plume and/or acidified brine may encounter up to several hundred wells. If carbon dioxide is geologically stored in regions, such as this, that have experienced intensive exploration for petroleum products, the acidified brine will come into contact with numerous abandoned wells. Corrosion of the cement that seals the well could lead to rapid leakage, so it is essential to determine the duration and intensity of exposure to the acid. Detailed numerical simulations with Dynaflow, incorporating a flash calculation to find the phase distribution and speciation in the brine, indicate that the carbonated brine may spend years in contact with the cement in abandoned wells. Preliminary results from an ongoing experimental study of cement corrosion indicate that the rate of attack is rapid, when the pH of the solution is low, so the risk of leakage will be high if the acidic brine can flow through an annulus and bring fresh acid into contact with the cement.

Experimental Study of the Impact of Drilling Fluid Contamination on the Integrity of Cement–Formation Interface

Flood experiments were conducted over 30-day periods at 14.48 MPa (2100 psi) confining pressure and temperature of 22 °C (72 °F) with cement–sandstone composite cores and brine at a flow rate of 1 ml/min. Higher pH values were observed in the effluent brine from the 10% mud contaminated core than the 0% mud contaminated core due to increased dissolution of cement. Microtomography revealed higher porosity at the interface zone of the 10% mud contaminated core. These show that mud contamination has a deleterious effect on the cement–sandstone interface and may create pathways for interzonal communication as well as sustained casing pressure.

Shale caprock integrity under carbon sequestration conditions

Carbon sequestration technology requires injection and storage of large volumes of carbon dioxide (CO2) in subsurface geological formations. Shale caprock which constitutes more than 60% of effective seals for geologic hydrocarbon bearing formations are therefore of considerable interest in underground CO2 storage into depleted oil and gas formations. This study investigated experimentally shale caprock’s geophysical and geochemical behavior when in contact with aqueous CO2 over a long period of time. The primary concern is a potential increase in hydraulic conductivity of clay-rich rocks as a result of acidic brine-rock minerals geochemical interactions. Both, mineral reactivity and microstructural characteristics, such as presence and development of fracture networks, may lead to potential leakage of CO2 to the surface or underground water sources. Bulk XRD analysis and Transmitted Light Microscopic imaging results acquired on six shale samples showed some heterogeneity in the shale caprock but the mine...

Comparative experimental evaluation of drilling fluid contamination on shear bond strength at wellbore cement interfaces

Wellbore cement has been used to provide well integrity through zonal isolation in oil and gas wells as well as geothermal wells. Failures of wellbore cement result from either or both: inadequate cleaning of the wellbore and inappropriate cement slurry design for a given field/operational application. Inadequate cementing can result in creation of fractures and microannuli, through which produced fluids can migrate to the surface, leading to environmental and economic issues such as sustained casing pressure, contamination of fresh water aquifers and, in some cases, well blowout. To achieve proper cementing, the drilling fluid should be completely displaced by the cement slurry, providing clean interfaces for effective bond. This is, however, hard to achieve in practice, which results in contaminated cement mixture and poor bonds at interfaces. This paper reports findings from the experimental investigation of the impact of drilling fluid contamination on the shear bond strength at the cement-formation and the cement-casing interfaces by testing different levels of contamination as well as contaminations of different nature (physical vs. chemical). Shear bond test and material characterization techniques were used to quantify the effect of drilling fluid contamination on the shear bond strength. The results show that drilling fluid contamination is detrimental to both cement-formation and cement-casing shear bond strength.

Impact of Physical and Chemical Mud Contamination on Cement-Formation Shear Bond Strength

The purpose of this experimental study was to investigate the impact of physical and chemical mud contaminations on cement-formation bond strength for different types of formation. Physical contamination occurs when drilling fluids (mud) dry on the surface of the formation forming a mud cake, while chemical contamination on the other hand occurs when drilling fluids which is still in the liquid form interacts chemically with the cement during a cementing job. Wellbore cement has been used to provide well integrity through zonal isolation in oil, gas and geothermal wells. It has also been used to provide mechanical support for the casing and protect the casing from corrosive fluids. Failure of cement could be caused by several factors ranging from poor cementing, failure to completely displace the drilling fluid to failure due to casing centralization. A failed cement job could result in creation of cracks/microannulus through which formation fluids could migrate to the surface which could lead to sustained casing pressure, contamination of fresh water aquifers and even blowout in some cases. To achieve proper cementing, the drilling fluid should be completely displaced by the cement slurry. However, this is hard to achieve in practice since some mud is usually left on the wellbore wall which ends up contaminating the cement. This study focuses on the impact of contamination on the shear bond strength and the changes in the mineralogy of the cement at the cementformation interface.

Mechanical Expansion of Steel Tubing as a Solution to Leaky Wellbores

Wellbore cement, a procedural component of wellbore completion operations, primarily provides zonal isolation and mechanical support of the metal pipe (casing), and protects metal components from corrosive fluids. These are essential for uncompromised wellbore integrity. Cements can undergo multiple forms of failure, such as debonding at the cement/rock and cement/metal interfaces, fracturing, and defects within the cement matrix. Failures and defects within the cement will ultimately lead to fluid migration, resulting in inter-zonal fluid migration and premature well abandonment. Currently, there are over 1.8 million operating wells worldwide and over one third of these wells have leak related problems defined as Sustained Casing Pressure (SCP). The focus of this research was to develop an experimental setup at bench-scale to explore the effect of mechanical manipulation of wellbore casing-cement composite samples as a potential technology for the remediation of gas leaks. The experimental methodology utilized in this study enabled formation of an impermeable seal at the pipe/cement interface in a simulated wellbore system. Successful nitrogen gas flow-through measurements demonstrated that an existing microannulus was sealed at laboratory experimental conditions and fluid flow prevented by mechanical manipulation of the metal/cement composite sample. Furthermore, this methodology can be applied not only for the remediation of leaky wellbores, but also in plugging and abandonment procedures as well as wellbore completions technology, and potentially preventing negative impacts of wellbores on subsurface and surface environments.

Chapter 10 – Leakage of CO2 Through Abandoned Wells: Role of Corrosion of Cement

The potential leakage of CO 2 from a geological storage site through existing wells represents a major concern. An analysis of well distribution in the Viking Formation in the Alberta basin, a mature sedimentary basin representative for North American basins, shows that a CO 2 plume and/or acidified brine may encounter up to several hundred wells. If carbon dioxide is geologically stored in regions, such as this, that have experienced intensive exploration for petroleum products, the acidified brine will come into contact with numerous abandoned wells. Corrosion of the cement that seals the well could lead to rapid leakage, so it is essential to determine the duration and intensity of exposure to the acid. Detailed numerical simulations with Dynaflow, incorporating a flash calculation to find the phase distribution and speciation in the brine, indicate that the carbonated brine may spend years in contact with the cement in abandoned wells. Preliminary results from an ongoing experimental study of cement corrosion indicate that the rate of attack is rapid, when the pH of the solution is low, so the risk of leakage will be high if the acidic brine can flow through an annulus and bring fresh acid into contact with the cement.

MICROSTRUCTURE AND MICROMECHANICS OF SHALE ROCKS: CASE STUDY OF MARCELLUS SHALE

Shale rocks play an essential role in petroleum exploration and production because they can occur either as source rocks or caprocks depending on their mineralogical composition and microstructures. More than 60% of effective seals for geologic hydrocarbon bearing formations as natural hydraulic barriers constitute of shale caprocks. The effectiveness of caprock depends on its ability to immobilize fluids, which include a low permeability and resilience to the in-situ formation of fractures as a result of pressurized injection. The alteration in sealing properties of shale rocks is directly related to the differences in their mineralogical composition and microstructure. Failure of the shale starts with deterioration at micro/nanoscale, the structural features and properties at the micro/nanoscale can significantly impact the durability performance of these materials at the macroscale, therefore, study at micro/nanoscale becomes necessary to get better understanding of the hydraulic barriers materials to prevent failure and enhance long-term geologic storage of fluids. Indentation tests were conducted at both micro and nanometer level on Marcellus shale samples to get the mechanical properties of bulk and individual phase of the multiphase materials. The mechanical properties map were created based on the nano indentation results and the properties of each individual phase can be correlated with bulk response in the multiphase composite; the effect of each component on the microstructure and bulk mechanical properties can be better understood.

Quantifying the Effect of Drilling Fluid Contamination on Cement-Formation Hydraulic Bond Using Scanning Electron Microscopy and Energy Dispersive Spectroscopy

The objective of this experimental study is to investigate the impact of physical and chemical mud contaminations on cement-formation shear bond strength for sandstone and shale formations. Physical contamination occurs when drilling fluids (mud) dehydrates on the surface of the formation, while chemical contamination on the other hand occurs when the drilling fluid (still in the liquid state) is mixed with cement slurry and reacts chemically with the cement during a cementing job. We investigated the impact of the contamination on the shear bond strength and the changes in the mineralogy of the cement at the cement-formation interface to quantify the impact of the contamination on the cement-formation shear bond strength.

Development of a New Physical Model for Experimental Assessment of Expandable Casing Technology Effect on Wellbore Cement Integrity

The focus of this novel research was to develop a physical model and apply an experimental approach to explore the effect of casing expansion technology on wellbore cement integrity.Copyright