Gas dehydration is a very frequent occurrence and a critical part of gas production offshore as well as onshore and therefore all the pertinent issues such as degree of dehydration, costs, design and operating "dos and don'ts" must be very well understood by the surface engineers as well as operators and managers. In the Middle East gas dehydration is particularly critical because of high reservoir pressures and high H2S/CO2 (sour gas) content and yet billions of cubic feet of gas are dried daily for gas injection or for downstream industry. But is the practice of gas drying in Middle East technically and environmentally adequate and safe?. If the water removed is not sufficient, liquid water is formed as pressure is dropped aiding line corrosion and upon further pressure reduction hydrates will form potentially blocking the flow lines. On the other hand extraction of too much water will cost the operator dearly and with the fluctuations in oil prices, revenues should be wisely used. The governing case which determines the degree of drying is the coldest operating condition for which the process gas may be subjected which means the degree of drying is a variable itself during the reservoir life and may be relaxed (or visa versa) as the reservoir life progresses and these are discussed in detail in this paper. There are various correlations used to arrive at the degree of drying and each give different results. In the proceeding paper, a range of credible dehydration methods are summarized with special emphasis on gas dehydration by TEG method as it is widely used and the salient points especially environmental issues related to the release of BTEXs into the atmosphere and how to minimize them. Various sets of correlations for dew point determination are demonstrated with real offshore case data together with unique and valuable recommendations on the design and costs optimization as well as technical/environmental safe operation.
Unconventional reservoir has become the hotspot of development in petroleum industry. In shale reservoir, some fracture is only propped by a monolayer 100mesh proppant. Fracture width is very small and under the condition of low rock hardness and high effective closure stress, the fracture will heal after a period of time, especially after the rock has been exposed to the fracturing fluids, causing weakening of the rock frame. In these reservoirs, proppant embedment becomes more serious. This paper purposes two embedment mechanisms, elastic deformation and creep deformation, and develops the corresponding models by combining simplified physical processes with elastic theory. Then with time integral, pressure dependent embedment depth is achieved. This paper provides a more reasonable method for calculating embedment. For fracturing engineer, it will give them a way to know how worse the matter will be. Finally, the model could couple with fracture propagation model and production prediction model to get a better result.
According to the results of analysis in the paper, in shale formation, proppant will cause creep deformation of rock, which will decrease fracture width with time. Optimization of fracturing fluid and treatment procedure are required to reduce the influence of creep deformation. Poisson's Ratio do have an effect on proppant embedment but very little. The mechanisms described in the paper provide a new understanding about embedment. It provides us a tool to determine how much the degree will be.
Chloride stress corrosion cracking (CSCC) on austenitic stainless steel sections of the oil and gas plants has been known to cause unpredictable failures, introducing high safety risks, and causing severe damage to equipment and loss of revenue.
This paper discusses three cases of CSCC at the Gas Recycling plant, Qatar Petroleum, Dukhan. The incidents have all been successfully rectified and also mitigated for the future, at a nominal cost.
The article describes the 3 cases in detail, explains the analysis conducted to determine the root cause of the failure. How evidence of CSCC was confirmed in each case and what mitigation measures were considered, how the most cost effective solution was identified and implemented. It also highlights the lessons learnt to prevent such failures, in the future.
Flawless Turnaround© complements existing optimisation elements (such as: scope & schedule optimisation and Turnaround Assurance Reviews) and facilitates continuous Quality delivery improvement by bringing increased rigour and emphasis to both, the operations and maintenance function. It is a fully integrated and proactive method designed to reduce the occurrence of all potential turnaround flaws.
The main elements are:
Systemisation is the process of breaking down the asset in smaller pieces. This process goes deeper than breaking down to a unit based approach, which is quite common in the industry. The unit will be cut in smaller pieces (systems). The systems will be identified prior to the event and all systems will become part of the integrated Turnaround schedule. System handover (from operations to maintenance and v.v.) will become part of the fully integrated schedule, that includes all activities; operations, maintenance execution and projects.
To help the organisation capture potential flaws that might take place during the execution of the Turnaround, a strict process will be put in place to try and prevent these flaws from happening. Specific Key success areas, e.g. Tightness and Cleanliness, will be identified prior to the event and focal points will be assigned for these areas. The focal points then take a leading role to identify and capture possible flaws and find mitigating actions to prevent these flaws.
- Rigorous Quality Assurance Programme
To ensure that the execution of the work has been done 'right first time' a comprehensive QA/QC process will be put in place. This process will be a joint activity, both by client as well as the contractor. Inspection and Test Plans (ITPs) will be developed with proper hold and witness points.
Flawless Turnaround© is a programme designed to help you achieve sustainable steady-state performance safely, quickly and within budget.
A change in Turnaround management
The cost of a turnaround consumes a substantial portion of a plant's maintenance budget, and there are constant pressures to execute turnarounds efficiently and effectively in order to maximise plant availability and production. Operating margins, competitive pressures and modern risk-based inspection techniques have driven companies to combine small turnarounds into larger ones and conduct them less frequently. However, the potential cost and duration benefits of fewer, but larger, turnarounds are often unrealized because staff has limited turnaround exposure and management systems or procedures are inadequate.
Benchmarking data have shown that the top-performing facilities actively address these issues and successfully complete turnarounds in half the time and at half the cost of their peer-group competitors. Shell has developed a Flawless Turnaround programme that is designed to take a proactive and integrated approach to turnaround management and thereby improve its performance.
Towards the later part of the 20thcentury, the oil industry has been looking for more safer and beneficial drilling methods, especially in deep waters. The high well/field costs pushed the need for attractive technologies which would optimize drilling. Also ever since the catastrophic events of April 2010 in the Gulf of Mexico, the oil industry has been constantly scrutinized for the health and safety standards or rather the lack of it. The consequences of the blowout highlighted the need for improved kick detection and well control. In deepwater wells, there exists a narrow window between the fracture pressure and the pore pressure. This narrow margin poses a safety hazard both for the well and the crew operating on it. Drilling in these sort of fields require distinctive methodologies to achieve both objectives of safe and optimized drilling.
Thus one such method which would optimize drilling and improve well control is Managed Pressure Drilling (MPD). This has been defined as "an adaptive drilling process to accurately control the annular pressure profile throughout the well??. This technique would create a pressure profile in the well to be within tolerance and close to the boundaries or limits controlled by the pore and fracture pressure.
The use of horizontal and multilateral wells in heterogeneous reservoirs has become well established over the last 10-15 years and has resulted in improved recovery and increased field life. Due to the non-uniform influx from these wells, less than 1/3 of the lateral contributes the bulk of the production from the well. The presence of an aquifer or gas cap can significantly shorten the well life and make it uneconomical. This is especially true for offshore fields where well intervention is difficult and expensive.
The use of ICD's or inflow Control Devices is becoming more prevalent and can result in significantly increasing the economic life of a well. Most of the devices currently in use are passive and once set, cannot be changed or modified. ICD's can be used for both producers and injectors and are very effective when used in conjunction. Prior to completing a well with ICD's, considerable design work needs to be done to determine the optimal settings for the life of the well. In order to properly design the ICD configuration, extensive simulations are required from the newly drilled well properties. A poorly designed well can result in choking production from good reservoir sections or resulting in early breakthrough.
This paper discusses the different types of ICD's available and the process to properly design the well completion. The different modeling tools available are presented and the implementation process in the field reviewed. Two field examples are given and the results from these installations presented. A process for the proper design and common issues are also presented. The use of screens coupled with ICD's for sand control is also discussed.
Gas hydrates are known to occur in deepwater environments (low-temperature and high-pressure) at various locations across the globe. When they occur close to the sea bed, hydrates present challenges to drilling, completing, and producing in deepwater applications. Additionally, many operators now consider these as a potential resource when they occur deeper within the earth, and there is increased focus on feasibly producing methane from gas hydrates. Safety, environmental impact, and economic viability are the foremost challenges faced by the upstream oil and gas community to unleash the potential that these unconventional reserves hold for the future.
Isolating the gas-hydrate-bearing zones by means of effective annular wellbore sealants is the prime factor that will contribute to the success of gas-hydrate campaigns. This paper addresses the current zonal isolation challenges likely to be encountered from the time drilling operation is completed until the plug and abandonment process is finished. With the considered lifecycle, a sealant system selection criteria based on commercially available technologies is proposed. While industry research on this front continues to progress, a holistic approach to designing a zonal isolation program to address the foreseeable challenges of unconsolidated formations, drilling-fluid removal in washouts, annular-sealant placement, battling lost circulation, prevention of hydrate destabilization, formation-fluid influx during the setting process, achieving good mechanical properties at low temperatures, and maintaining long-term sealing integrity throughout the life of the well is discussed and evaluated.
The design approach involves (1) preliminary engineering sensitivity analysis to judge the effect of dominant parameters on sealant system design, (2) selection of commercially available, fit-for-purpose materials and laboratory testing, and (3) validation by means of confirmatory analyses. The approach presented is an incremental effort to help operators and industry researchers increase the productivity of gas-hydrate-bearing wells.
Mud acid, which is composed of HCl and HF, is commonly used to remove the formation damage in sandstone reservoirs. However, many problems are associated with HCl acid, especially at high temperatures. To overcome many of these drawbacks, organic-HF acids have been used as an alternative to mud acid. However, very limited research has been performed to reveal the reactions between organic-HF acids and minerals in sandstone reservoirs.
In this study, formic-HF and acetic-HF acids were examined to react with various clay minerals (kaolinite, chlorite, and illite), in comparison with mud acid. A series of acid mixtures with different ratios and concentrations were tested. Inductively coupled plasma (ICP), scanning electron microscopy (SEM) and 19F nuclear magnetic resonance (NMR) were employed to follow the reaction kinetics and products. Core flood experiments on sandstone cores featured with different mineralogy, with dimensions of 1.5 in. × 6 in. were also conducted at a flow rate of 5 cm3/min. The core effluent samples were analyzed to determine concentrations of Ca, Mg, Fe, Si, and Al by ICP.
Both formic-HF and acetic-HF acids are much milder than mud acid. The species and amounts of reaction products of different clay minerals in organic-HF acids depend on mineral type, acid composition, and ratio. This conclusion is further confirmed by core flood experiments, in which sandstone cores with different mineral compositions give quite different responses to the same acid mixture. This paper will discuss the detailed chemical reactions that occurred within cores and were followed by chemical analysis of core effluent samples.
One of the current largest oil increments in the world in Saudi Arabia is undergoing field development. The southern part of the field traverses the Arabian Gulf Sea. The Production Engineering team crossed major hurdles in the development of this field with Causeways construction on artificial islands over drill sites to assess well sites.
Flowback options on wells in these drill sites to unload drilling fluids presented key challenges. The flowback objectives included well cleanup, stimulation, production logging, and extended well tests for reservoir characterization requirements. Flowback would also allow conducting electric submersible pumps (ESP) spin tests prior to ESPs installation.
A smokeless flaring option considered the heavy crude's characteristics with relatively high H2S content, possible emulsions from intermixing with completion fluids, interwell spacing limitations, and the sensitive nature of the nearby challenging marine environment. The choices were between using a conventional flare system and modifying the proposed layout to optimize the project's objectives while respecting the constraints imposed by a sensitive aquatic environment, highly sour crude, space limitations, and work conditions or implementing pre-existing conventional practices with the attendant risks of compromising health, safety, and environment.
The authors examine the processes leading to the implementation of a smokeless and an environmentally friendly flowback option. The discussion includes the modifications made to the burner system, and H2S removal from the gas and oil phases. Also a new methodology is presented that fully controlled oil and gas flow to the burner to mitigate the risk of burner flameout for the highest burning efficiency, minimizing spills, and enhancing safe operation. The authors examine the pros and cons of other welltest options such as to re-inject produced fluids into the same reservoir, different reservoirs, or injection into water injectors.
Key significant technical contributions include the presentation of several practical measures to avoid oil spills, and to guarantee ambient air quality. The welltest layout included several automation systems or the elimination of human interventionto deliver safely the project's objectives.
The drill sites sit on artificial islands constructed from piles of gravel and sand in about 22 feet of water. The Causeway concept itself was borne out of a need to protect the beds of sea-grass and algae in X bay, which supply abundant food for aquatic existence. The beds of sea-grass and algae are therefore the perfect home for species like shrimp, dolphins, crabs, fish, sea turtles, oysters, and some endangered classes. A prime objective was to sustainably manage the X field development while preserving this inherited fragile but untainted legacy of the environment. In addition to the sensitive marine habitat, proximity to public areas, limited well spacing, and a relatively high H2S amount in the crude all contribute to the challenging nature of this field development.
Qatar Petroleum is committed to trying to achieve zero gas flaring. We have carried out important field changes to reduce it. As a result, we have significantly reduced gas flaring, recovered more hydrocarbons, protected the environment, and made financial gains by optimum utilization of the field existing infrastructure.
Gas Flaring is an important aspect of oil and gas field operations. It provides a safe relief for the production facilities whenever excess fluids or out of specification products need to be released. However, it has an adverse effect on the environment that needs to be resolved. Also valuable by-products could be recovered.
QP applied environmental regulations and drew on our experience to evaluate flaring sources and devise plans to mitigate flaring. We used recommendations from our evaluation studies to identify the necessary operational actions and plant changes.
We have identified four main factors affecting flaring: 1) field development planning 2) the design, construction, operation, and maintenance of field processing facilities 3) investment economics and 4) regulatory instructions. The operational actions and plant changes that we made have reduced gas flaring. Many other projects and studies are in progress to reduce flaring and ensure we comply with environmental protection requirements.
This article explains the Qatar Petroleum flaring philosophy and the changes and modifications completed or in progress in Dukhan field that reduce flaring as we aim to achieve "Zero Flaring."
Dukhan Oil Fields operations date back to the early 1940s. The field is located on the west coast of the state of Qatar peninsula. It covers an area of approximately 640 km2 and produces about 360 - 370 MMSCFD of raw associated gas (RAG) in seven oil & gas separation units in addition to 800 MMSCFD of rich condensate cap gas.
RAG gas is sent partly to a gas lift station while the remaining RAG is sent to the Dukhan central gas processing plant for (NGL) heavier liquid hydrocarbon recovery.
The by-products of the central gas processing plant are stripped associated gas (SAG) and flash gas generated from NGL recovery and stabilization. SAG and flash gases are injected into the government fuel gas network and partly used as feed stock to Mesaieed petrochemical processes.
For reference, Figure #5 illustrates a typical degassing station as installed in the Dukhan field and Figure #6 describes the central gas processing plant.
Besides degassing stations, the condensates recovery plant receives about 800 MMSCFD from non-associated gas (Cap gas) to produce stabilized condensate and raw NGL to be exported by pipeline to Mesaieed Industrial Area for further processing.
The remaining lean gas is compressed up to 195 barg and re-circulated back into the Arab-D cap gas reservoir to maintain reservoir pressure and further enrichment stripping cycles.