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Case Studies
A large liquefied natural gas (LNG) producer, with multiple plants along the Gulf Coast, required standard leak testing services during the commissioning and startup phase for their newest plant.
An Independent E&P Company operator’s main 6” infield flowlines on the Gulf of Mexico shelf had been experiencing problematic organic deposition, ultimately rendering it inoperable. The production was re-routed through a parallel 4” line that allowed for production to sustain while the paraffin-stricken line was temporarily abandoned.
An independent oil operator experienced four back-to-back casing failures in his Oklahoma shale program. These current failures and setbacks were eating into his budget and eroding stakeholder faith in the ability to complete wells.
His initial comment was, “I’m not getting any sleep – I need some help. You’ve got to help me stop the leaks!”
A winter-peaking natural gas storage plant undergoes a production expansion which includes infill well drilling and a gas compression system expansion.
A mid-size upstream operator experienced progressively lower flow rates as the result of solids restrictions. Routine pigging procedures were not applicable on the produced water system, as the HDPE product pipe configuration was considered to be unpiggable with conventional methods. This liability reduced the engineering startup flow rates drastically, which initially calculated a rate to move produced water equal to or faster than the production rate. Slower flow rates impeded production and ultimately had a negative reflection for the production asset.
A GoM upstream operator engineered a pre-existing 22” gas pipeline and a pre-existing 8” oil pipeline for common use. This re-engineered scope eliminated CAPEX costs on installing a new pipeline and decommissioning costs on removing the in-service assets by utilizing in-place assets to achieve the new production requirements.
A midstream operator sought flow assurance and integrity services for a gas pipeline with blockage concerns. The unknown location and makeup of the pipeline restriction prevented the operator from performing routine pigging operations. In order to remain compliant with current regulatory standards, a sound remediation method that targeted the blockage area was required in order to successfully plan and execute a hydrostatic pressure test.
An operator of a Liquified Natural Gas (LNG) offshore loading facility required mechanical torque value verification on multiple structural assemblies in order to abide by the manufacturer’s recommended specifications and standards.
An operator of an onshore Liquefied Natural Gas (LNG) micro fuel facility sought integrated solutions from a single source contractor. Ongoing activities with multiple construction groups were working compressed schedules in order to ready the facility for a re-purposed product. Direct technical commissioning support became an value target during the early phase of project execution, as pressure testing and torque value verification for 600+ connection joints demanded specific expertise.
A Gulf of Mexico operator required a safe method to dewater a subsea pipeline upon a recent integrity test. Previous attempts to dewater the pipeline of the hydrotest medium with a foam pig proved unsuccessful. Importantly, the said pipeline was documented to contain heavy paraffin accumulation. Furthermore, the pipeline asset required an application that could mitigate the multi-diameter profile while assuring the client of a complete dewatering task. BlueFin’s casted SoliGel pig was designed to travel throughout the different pipeline diameters while mitigating flow assurance challenges and using production gas as the propelling medium.
A midstream contractor required competent, turnkey commissioning solutions in order to meet an established start-up date. The project consisted of 225 miles of 24 inch NGL pipeline in West Texas. Knowledge of pipeline integrity parameters, SIMOPS scheduling, logistical resources, and proven field personnel were critical to project award approval.
A Gulf of Mexico operator planned a well re-completion of a new reservoir and planned to use an existing flowline. Historical data determined significant paraffin deposition across the flowline. Due to well reservoir modeling analysis, the preexisting flowline warranted an aggressive but confident cleaning program to ensure that the volume capacity was realized.
A pipeline operator required a full line hydrostatic test of a 22-inch crude oil pipeline. The line would be tested in 4 segments. During initial line fill, the pig got hung up and bypassed nearly the entire line fill volume. Once the decision to move forward was made, BlueFin sourced equipment and refilled the line with an alternative water source within 3 days. One segment failed initial test. After repairs, all four segments were successfully tested using electronic data to justify pressure changes.
Startup engineering requirements specified that produced water flow rates should be equal to or faster than the production flowrate. Lesser flowrates would impede production and ultimately create problems in the production schedule and budget. After a considerable production timeline, the operator began to experience severe flow assurance issues on the produced water pipeline as the result of solids buildup.
A major midstream gas transmission company required stress corrosion cracking (SCC) integrity assessment services by hydrotesting to remain compliant with regulatory specifications. The project consisted of a single 101.9 mile pipeline with both 24 inch and 26 inch diameter pipe. Significant environmental hazards were encountered from pipeline contaminants. Additionally, unknown to the pipeline operator, the pipeline contained a significant amount of debris.
eelReel successfully used to remove stuck pig and paraffin and restored production.
A GoM operator of a 6-inch subsea oil production flowline experienced severe paraffin blockage. The said deposition prevented a successful hydrocarbon de-inventory procedure in order to properly abandon the asset per compliance regulations. Due to insufficient pump rates, the operator faced expensive, complex subsea intervention tasks based upon routine flow assurance methods typically applied in decommissioning scopes of work.
An operator of a mini-TLP experienced flow assurance problems in a subsea oil production flowline system. Operator knowledge and production history identified the issue as a paraffin blockage. Unsure of the blockage location and remediation method, several failed attempts at pressure cycling from the subsea and platform sides resulted in a mechanical remediation need.
A GoM operator experienced problematic pressure differentials over a period of time, ultimately resulting in a completely plugged 6” flowline. Heavy paraffin solids completely plugged the flowline and prevented the transportation of liquid product. Upon an evaluation of available remediation methods, an extended reach mechanical solution was selected.
eelReel successfully used to remediate completely plugged 6” pipeline.
A major midstream operator required decommissioning solutions for an aged gas pipeline asset. In order to properly abandon the said infrastructure in compliance with BSEE and state regulatory departments, engineering managers determined that an inert gas medium would mitigate several risks. As important, the asset contained a large amount of residual liquid product that required safe capture and disposal.
A midstream company required a Department of Transportation (DOT) integrity assessment on a 30-inch transmission gas pipeline. In order to meet federal compliance standards for continued gas operations, the operator elected to execute a hydrostatic pressure test between an existing compressor station and a mainline valve location.
A Gulf of Mexico upstream operator required pipeline abandonment solutions for one 6 inch pipeline. The operator’s permitted Department of Interior (DOI) decommissioning obligation required a seawater flush volume equal to 110% of the internal pipeline capacity.
A major midstream gas transmission company required Stress Corrosion Cracking (SCC) integrity assessment services to remain compliant with regulatory specifications. The pipeline was installed in the 1970s and was located in an environmentally sensitive area with high stakeholder interest and visibility. Further increasing project sensitivity, the pipeline owner expected multiple ruptures during the hydrostatic pressure tests phase. In order to compensate for this risk, an extensive outage period was scheduled and communicated to all customers.
A GoM upstream operator experienced problematic pressure differentials. Over a period of time this resulted in heavy paraffin deposition and ultimately caused several pigs to become stuck in the 6” flowline. Upon an evaluation of available remediation methods, an extended reach mechanical solution was selected to remove the lodged pigs and properly remediate the paraffin deposition.
A GoM operator witnessed a leaking 6” pipeline. Upon repairing the visual leak and attempting to perform a successful hydrostatic pressure test a second non-visual leak occurred, ultimately resulting in extended production loss.
In order to perform a second assessment and bring production back online, the pipeline assessment required a 100% fluidpacked volume of seawater to ensure an oxygen-free environment.
A major midstream gas company required a Stress Corrosion Cracking (SCC) integrity assessment in order to remain federally compliant. The project schedule was of critical importance due to the customer’s demand date for product transmission. This schedule demanded that BlueFin couple engineering subject matter experts and management resources to deliver a work plan that would meet the customer’s deadline.
SafeHeat® technology, custom thermal fluids, and flow assurance engineering provide total approach for plugged GoM pipeline.
Technical expertise and responsive management provide GoM operator with a successful offshore gas pipeline reinstatement.
Integrated mechanical and pipeline services provide bundled solutions for independent GoM operator.
Technical Articles & E-Books
So your pipe burst, your pump shaft snapped, or your welded joint split, and you need to figure out why and how to fix it. The next steps you take can make the difference between finding answers and leaving the mystery unsolved until the next failure.
We have many options for conducting root cause analyses (RCA) including TapRooT™ and CAST/STPA. The method described here is the method developed by GATE to simplify the analysis while maintaining adequate rigor.
Systems Theoretic Process Analysis (STPA) is a systems approach to hazard analysis. It is based on the premise that accidents happen when we lose control. They are a control problem, not a failure problem.
The GATE approach to risk ranking makes risk assessment easier, more accurate and more repeatable by incorporating LOPA insights into the risk matrix approach.
HAZOP is the most commonly applied process hazard analysis (PHA) methodology in the processing industries. It is also the most flawed!
This article discusses high-level technical considerations when refitting an existing offshore infrastructure for CCUS applications.
Energy is changing. Because of the increasing threat of the consequences of a warming planet, new sources of energy are being developed that are expected to slow this planet-wide change. Some of these are well-known, such as nuclear, wind and solar, while others require more work, such as hydrogen, 3rd generation concentrated solar and fusion.
The overall aim of carbon capture and sequestration (CCS) is to store carbon dioxide (CO2) in geological formations in order to reduce the amount in the environment and lower the risk of catastrophic climate change. The rate of CO2 emission and the amount of it in the atmosphere has been increasing steadily since the beginning of the Industrial Revolution in the early part of the 19th century.
There are several developments in the area of electrolysis which seek to reduce the cost, increase the yield, or even change the source of transportable hydrogen.
Making Risk Assessment Better, Less Ambiguous and Repeatable - And more Actionable
The recent global over supply of crude oil and soft demand has resulted in oil companies shutting wells in to prevent destroying value and to protect their balance sheets. The time frame, until production startup becomes economic, is uncertain and therefore, it is imperative that appropriate actions are taken to maintain and manage the integrity of shut-in wells and associated delivery systems.
The time frame, until production startup becomes economic, is uncertain and therefore it is imperative that appropriate actions are taken to maintain and manage the integrity of the available Installed Production Capacity during shut-in.
Circuitization aims to reduce overhead inspection costs through the thoughtful break down of a system into smaller sections.
In recent years, the BSEE Safety Inspection Program section has been developing a risk-based approach to augment these inspections.
This information provides insight to aid in preventing common failures and improving industry practices to reduce incident rates in addition to saving time and money.
Now its time to assess the TOLC risk and the corresponding locations in the system where TOLC may occur. From there we can determine the appropriate mitigation and control strategies.
The building blocks of a robust inspection program are condition monitoring locations (CMLs). As defined by API 510 and API 570, CMLs are designated locations on pressure vessels or piping systems where periodic external examinations are conducted to assess condition.
At GATE Energy, we have the technical knowledge and experience to apply our own approach to souring prediction which can enable design and operational decisions to be made to mitigate the risks associated with such H2S production.
Seawater injection is a vital tool for the economic success of some projects and those projects need to ensure that the seawater can be effectively delivered from the seawater source to the reservoir.
In Part 2 of this GATEKEEPER series, we will look at the different approaches available to assess risk in the system and will discuss the mitigation options available to us.
In determination of consequence and risk assignment, multiple aspects are considered such as the impact of failure on the health and safety of personnel and community in the impacted area, environment, cost of recovery (cleaning, maintenance, extent of operation, repairs) and business.
Oil well stimulation is commonly undertaken using aqueous solutions of hydrochloric acid (HCl), hydrofluoric acid (HF), organic acids or mixture. The use of these acids will open new channels near the wellbore region for the oil and gas flow through and will result in increased production.
In this GATEKEEPER, the philosophy around the materials selection and corrosion monitoring is discussed as the primary design barrier to corrosion and cracking in critical parts of a subsea system.
This book is an exploration of what decision theory has to say about these and other common engineering problems.
The GATE Stream-based HAZOP process avoids these pitfalls via some novel modifications to the process. You can obtain a copy of the book here.
The following material properties are important when understanding the limitations of API 5CT high strength steels: yield strength (YS), Charpy V-notch (CVN) impact energy, hardness and tempering.
This GATEKEEPER article focuses on the prediction, prevention and remediation of liquid loading, including discussion of liquid loading analysis.
The objective of this GATEKEEPER is to provide a high-level overview of the model commonly used in the industry to estimate the wax deposition.
The design and development of a viable, robust wax management strategy relies upon the economical evaluation of available management techniques.
This series of two articles discusses the diagnosis, detection and remediation of oil and gas production system blockages in detail. The current issue focuses on blockage characterization and detection.