Geothermal brines typically contain dissolved minerals and gases that can cause calcium carbonate silica/silicate and iron sulphide scale deposition in wells and on topside equipment. The presence of scale within a geothermal system can cause various issues that can lead to decreased efficiency of thermal energy production.The high temperatures of geothermal wells can create quite a challenge for scale control in terms of inhibition performance and thermal stability and this limits the chemistry of scale inhibitors that can be applied under these conditions. For calcium carbonate scale control phosphonates often display better inhibition capability than polymers as well as increased brine tolerance.However the thermal stability limits for low molecular weight phosphonates which typically provide good calcium carbonate inhibition are limited to 170°C- 200°C and this temperature can often be too low for geothermal wells. There is therefore a need to develop a novel phosphonate chemistry with a higher temperature stability up to 250°C for geothermal application.The thermal aging data at 250°C for the novel phosphonate chemistry will be presented and furthermore for calcium carbonate details will be provided of scale inhibition performance testing in geothermal brines compared with other traditional phosphonates and polymeric scale inhibitors at 250°C. The calcium carbonate inhibition performance was determined using dynamic scale loop (DSL) tests using a standard industry technique adapted for high temperature geothermal conditions.This study presents details of the development of novel phosphonate scale inhibitor that has been designed to work against calcium carbonate scales at temperatures up to 250°C. The new product is biodegradable calcium tolerant and has the capability to be deployed by continuous injection or in downhole scale squeeze treatments if necessary.

As the oil industry continues to operate in more complex and ultrahigh temperature environments scale control becomes an ever increasing challenge. Scale inhibitors are being pushed to their operational limits and start to lose their efficiency against both calcium carbonate and calcium sulphate scales at >200°C. It is therefore essential to develop the next generation scale inhibitor to work effectively in harsh high temperature environments such as steam floods and geothermal wells.In this study details will be provided of the thermal stability of a novel biodegradable phosphonate scale inhibitor at temperatures up to 250°C. In addition examples of calcium sulphate and calcium carbonate scale control will be provided at 200°C and 250°C respectively where the inhibition performance of the novel phosphonate has provided significant improvements compared to other phosphonates and polymeric scale inhibitors known to be stable at high temperature.The work for calcium sulphate has focussed on steam flood applications where downhole temperatures reach ~200°C and the scale inhibition performance was tested using dynamic scale loop tests based upon a known industry standard procedure. Calcium carbonate inhibition was also tested at 200°C using a similar procedure and in addition with a geothermal brine at 250°C.  The new phosphonate scale inhibitor has also been designed to be biodegradable and can be deployed by both continuous injection and scale squeeze treatment. Careful consideration was also given in the molecular design process for high calcium tolerance and details of brine compatibility at high temperature will be provided.This paper presents details of the development of a biodegradable thermally stable and calcium tolerant phosphonate scale inhibitor for both calcium sulphate and calcium carbonate scale control in ultrahigh temperature environments at ≥200°C. In addition the environmental test data will be discussed along with a field example of deployment of the new phosphonate scale inhibitor for calcium carbonate scale control in a high calcium brine (30000mg/l) in West Africa.

Slurry pipelines are critical systems used in oil sands mining operations to efficiently transport ore from the mine site to centralized extraction facilities. One of the main challenges in designing these systems is the screening and selection of optimal pipeline materials. Slurry pipelines in oil sands mining (hydro-transport and tailing lines) are subjected to aggressive abrasion and erosion-corrosion conditions resulting in relatively rapid material wear rates. For some operations the degradation of these pipelines can result in significant maintenance and replacement costs. To address this issue operators are constantly looking for new material systems which can be used to increase wear resistance and run-life of pipeline systems. Numerous lab-scale test methods exist to assess and rank the ability of materials to resist abrasive conditions but no definitive method is recognized as a standard by industry (other than costly field testing). In the first part of this paper the relative merits of a number of currently available lab-scale testing methods used to characterize material wear are critically assessed. To highlight these merits comparative tests were performed on a variety of materials including a number of polymers and carbon steel. Results show that the ranking of material performance varies with test method used and highlights the importance (and difficultly) in selecting an appropriate test method that represents actual service conditions.In the second part of this paper the development and preliminary assessment of a novel wet wheel abrasion test apparatus is showcased. The intent of this new method is to better simulate the wear mechanisms found in multiphase pipelines with dense-bed slurry flows. Preliminary tests were performed on a number of novel titanium-carbide (Ti-C) reinforced polyurethane materials with two distinct particle size ranges. Performance was evaluated by comparing results to a conventional steel alloy commonly used by the industry and an unreinforced polyurethane system. Wear mechanisms were assessed through microscopy and wear scar profile analysis. A discussion is also provided of the key benefits of this test method (including the potential for assessing the effects of dissolved oxygen and/or fluid chemistry effects) and future work required to validate this novel test system.

This paper will outline the development of a novel Yellow Metal corrosion inhibitor with improved corrosion control capabilities when compared to traditional Azole technology. A four-year R&D effort has led to a new patent pending molecule that develops a more robust film greatly reducing the impact of high levels of halogen on the corrosion of copper and copper alloy heat transfer surfaces. This paper will briefly outline laboratory corrosion testing and film formation and focus on field applications.

Most of the corrosion prediction models used for design of oil and gas lines carrying high pCO2 are valid up to 10-20 bars of pCO2 and are very conservative at higher pCO2 because they do not account for the effect of high pCO2 on the water chemistry and the corrosion mechanism. The present work was focused on developing a predictive tool for near-critical and supercritical CO2 corrosion of mild steel. It incorporates changes in the water chemistry module due to update solubility and dissociation equations changes in the electrochemical module due to the presence of a thick and porous corrosion product layer and consideration of an adsorption mechanism for H2CO3 at the steel surface. The comparison between experimental results and model predictions showed a good agreement under various pressure and temperature ranges.

Third Party Damage (TPD) represents the largest threat to the integrity of onshore oil and gas pipelines. There exist needs for developing reliable models that can quantify the probability of pipeline exposure to TPD threats. Bayesian network(BN) modeling possesses the advantage to quantify the uncertainties and identify where the reduction of these uncertainties has the greatest benefit in terms of the overall failure. This paper reports a modeling approach using Bayesian Network to quantify the Mechanical damage (a major form of TPD) threats to pipeline. Case studies to exam excavation and moving vehicles damages to the pipeline were reported where the conditional probability tables (CPT) of the model were created based on the pipeline operator’s records public data-bases and literatures as well as information obtained from Subject Matter Experts. This model examines TPD failure mechanisms in three parts including Exposure (likelihood of a force or failure mechanism reaching the pipe when no mitigation applied) Mitigation (actions devices conditions etc. that keep the force or failure mechanism off the pipe) and Resistance (the system’s ability to resist a force or failure mechanism applied to the pipe). Using this model pipeline segment with a higher risk to excavation and moving vehicles damages can be identified and suitable mitigation technology can then be implemented to reduce the risk.

Regulatory groups require gas storage facility operators to address the safety and environmental concerns that would be impacted due to a release of the processing fluid. The objective of this paper is to disseminate a process that operators can use to develop an ultrasonic thickness (UT) monitoring program with reliable and reproducible results that meet the fitness-for-service requirements set forth by industry. This paper targets Class 1 Type A components using a Level 1 assessment approach. These components represent the high risk assets subject to design equations that specifically relates to pressure and where supplemental loading does not govern required wall thickness i.e. the required thickness is based on pressure only. A systematic approach to the organization and implementation of the program complete with mathematical equations to evaluate components for fitness-for-service requirements and justification for asset retirement is provided.

Over the past several years, the Bureau of Reclamation’s Materials Engineering Research Laboratory has been developing and refining a test method to evaluate a coating’s resistance to erosion damage in sediment-laden immersion exposure. This test has initially been utilized as a screening/ranking method in selection of new coatings for the aforementioned severe service environments. 

Waterflooding is a common secondary recovery technique where injection water (IW) is used to maintain reservoir pressure and improve oil recovery. During such operations, the mobile hydrocarbon phase is displaced along with formation water (FW) toward producing wells. The resulting produced water stream is a blend of FW and IW; these waters can be incompatible resulting in dissolved ions to precipitate out of solution as mineral scale.

Top-of-the-line corrosion (TLC) of carbon steel (CS) pipelines can be encountered during the transportation of wet gas under stratified flow conditions where temperature differences between the internal and external environments results in condensation of saturated vapors and water-wetted surface on the upper portion of the inside pipeline surface causing corrosion issues.1 Initially at least, the condensed water phase can be particularly corrosive with a low pH caused by dissolved acid gases (such as carbon dioxide and hydrogen sulfide) as well as organic acids in an unbuffered thin water film. Like bottom-of-the-line corrosion, TLC can be dominated by either carbon dioxide or hydrogen sulfide corrosion mechanisms.

Corrosion inhibition is the preferred choice of internal corrosion control of carbon steel pipelines and downhole tubulars for many oil and gas operators. The selection of a corrosion inhibitor (CI) is often system dependent because a CI that performs well under one set of conditions may not always do so under another. Thus throughout the world a huge number of CI products are available and deployed to attend to the wide and varied operating environments encountered in the oil and gas industry to mitigate carbon steel corrosion. Consequently this often requires operators to have to handle numerous chemical products to treat different fields and/or to replace CIs for the same asset as the field conditions change over time. Since this can pose challenges to operators from a logistical viewpoint it is advantageous for a CI to have a wide window of operability in order to help reduce the number of products an operator has to manage.A recent R&D effort has focused on the development of a highly versatile CI product which has been specifically formulated using a unique backbone of chemistries to inhibit carbon steel corrosion in a broad range of operating environments. Furthermore it has favourable product attributes to enable it to be handled and applied in many regions of the world via various application methods. Through a number of examples this paper demonstrates the high level of corrosion inhibition performance and adaptability of the newly developed CI product under a number of simulated field laboratory testing conditions including at low and high shears using sweet and sour gas mixtures and differing brine compositions and temperatures. The new product also demonstrates favourable secondary and physical properties in terms of low foaming and emulsion tendency good product stability at various temperatures as well as passing key assessments for application via umbilical and downhole capillaries. Keywords: carbon steel corrosion inhibitor sweet sour carbon dioxide hydrogen sulphide localised corrosion pitting

Inspection of ballast tanks and enclosures is generally performed using traditional methods such as
visual inspection and non-destructive evaluation (NDE) techniques. However, it is common for these
methods to often be labor intensive and limited by physical restrictions that prohibit access to certain
areas. Further, the evaluation of the coating condition is heavily dependent on the inspector, and the
quality of the data gathered is varying.