The ESP system is an important artificial lift method commonly used for medium- to high-flow-rate wells for subsea developments. Multiphase flow and viscous fluids can cause severe problems in pump applications. Free gas inside an ESP causes operational problems and lead to system failures. Under two-phase flow conditions, loss of pump performance or gas lock condition can be observed. Under viscous fluids, the pump performance degrades as well. This paper provides a model on the effects of viscosity and two phase (liquid & gas) fluids on electric submersible pumps (ESPs), which are multistage centrifugal pumps for deep boreholes. The theoretical study includes a mechanistic model based on Barrios (2011) for the prediction of the degradation due to bubble accumulation. The model comprises a one-dimensional force balance to predict occurrence of the stagnant bubbles at the channel intake as a main cause of deviation from homogeneus flow model.
The testing at Shell's Gasmer facility revealed that the ESP system performed as theoretical over the range of single flowrates and light viscosity oils up to Gas Volume Fractions (GVF) around 25%. ESP performance observed gas lock condition at gas fraction higher than 45%. Homogeneous Model has a fairly good agreement with pump performance up to 30% GVF. Pump flowrate can be obtained from electrical current and boost for all range of GVF and speed. Correlation depends strongly in fluid viscosity and pump configuration.
The main technical contributions of this study are the determination of flow patterns under two important variables, high viscosity and two-phase flow inside the ESP to predict operational conditions that cause pump head degradation and the beginning of bubble accumulation that lead to surging Barrios (2011). For similar applications, pump performance degradation can be predicted in viscous environment and two-phase flow conditions.
DOST - Directorate Operations Strategy Team was formed in year 2007 to develop Operations Directorate long term vision. Inspired by Qatar National Vision - QNV2030 and fuelled by Qatar Petroleum "Commitment to Excellence??, DOST has made significant strides in developing a shared Operations Directorate Vision - ODVision2020 under an innovative and unique LEADERSHIP concept.
This paper highlights the DOST journey in establishing the Operations Directorates Mission, Vision and Values as well as developing broad Objectives, Strategies and Roadmap based on SWOT analysis, cultural surveys and interviews carried out across the ranks. The paper will also present the challenges anticipated in realization of ODVision2020 and how organizational people, processes and systems would be transformed and Operations Directorate emerges as a leader in the industry in all aspects of its business.
Most of the existing correlations for estimating gas viscosity were developed in mid 60's and 70's of the last century. Limited number of data was used to develop them and their accuracies are questionable. Predicting accurate gas viscosity is extremely important in the oil and gas industry as it has a major impact on reservoir recovery, fluid flow, deliverability, and well storage.
In this study, a new correlation has been introduced. This correlation is simpler, features higher accuracy, and uses fewer coefficients compared with the existing correlations. Its application covers a wider range of gas specific gravity without jeopardizing the accuracy of the correlation. Another model was built using Artificial Neural Networks, ANN in order to compare its results with those obtained from the new correlation.
The existing correlations were studied and analyzed using the same, large set of measured data used for this study. Most of these correlations suffered from high errors and thus were optimized using the linear and non-linear regressions. New set of coefficients for these correlations are recalculated for which the accuracy has significantly improved. In spite of such an improvement, the new correlation and new ANN model outperform the existing correlations.
Many correlations have been proposed for gas viscosity estimation. These methods include Carr, et al., Jossi, et al, which was adapted by Lohernz, Bray and Clark, Dien and Stiel, Lee, et al. and Sutton. Carr, et al. 1 correlation has been very popular for estimating gas viscosity. Lee, et al. correlation has been used widely since mid 80s as it has proven to be more accurate. Each of these correlations will be discussed briefly below. The corresponding viscosity correlations are shown in Appendix A.
1. Carr, et al.1- Dempsey2-Standing3 method
Until recently, this correlation was considered to be the main correlation for estimating gas viscosity in petroleum industry. Carr, et al.1 used their experimental data (and Comings, Mayland, and Egly data) to create a graphical correlation, as function of reduced pressures and temperatures. Results were used to construct cross plots, which were a function of pseudo-reduced pressure, pseudo-reduced temperature and viscosity ratio. The main advantage of this correlation is its simplicity as well as the corrections it has for the existence of non-hydrocarbon gases such as CO2, N2 and H2S.
Carr, et al.1 correlation is reported to have an average of 0.38 absolute error. This correlation is recommended to be used for gases with specific gravity between 0.55 and 1.22 and a temperature range between 100 and 300 ºF.
Dempsey2 (1965) expressed the viscosity ratio for Carr, et al.1 chart µg/ µ1 mathmatical formula as shown in Appendix A.
Production optimization for offshore oil and gas production is in general a challenging task, even at fields operated "Smart" with continues 24/7 optimization, due to the intrinsic complexity of the domain. In this paper, we present an intelligent multi-objective-control-software approach for the next generation of Smart Fields.
At the DONG Energy E&P operated Siri area, which we use as a test case, several optimization studies have shown that an increase in production throughput is possible, if the comfort zone, i.e. the band between the actual and the maximally possible production level, is reduced dynamically. Maximal production will be obtained when the comfort zone meets the minimally required margin that ensures a safe and stable production in all constraining systems of the installation. This can be hard for the control operators to achieve with the present complex dynamic production configurations.
In our approach, we focus on intelligent online control to minimize the comfort zone by pushing the production towards the process constraints which always have to be satisfied. The new intelligent online multi-objective control system is implemented as a stratified multi-agent system allowing control concerns to be dynamically introduced, changed or removed without the need to modify or inspect the existing control system. The stratified approach supports multi-objective optimization in all layers, i.e. in contexts of strategy, tactics and operation. Optimization conflicts are dynamically identified and propagated to a higher layer. The "irony of automation" predicts that more advanced automation systems require more tacit knowledge; an essential property of any advanced control system is, therefore, the capability to identify and explain optimization conflicts well in advance.
In this paper, we demonstrate that it is possible to continuously minimize the comfort zone and thereby gain higher production throughput by using intelligent online multi-objective control, even at fields with complex configurations.
The exploitation of an oil field in deep water presents many challenges related to high water production, high cost of frequent well interventions and many uncertainties. One of the technologies available, which can overcome these problems, is the use of intelligent wells (IW), which are capable of reducing water production rates, to avoid intervention in the well and to add operational flexibility to mitigate risk. However, the real benefits of this technology are not always clear due to the lack of a consolidated methodology in the literature. Moreover, there are also two main ways of controlling valves, i.e., reactive and proactive controls, making it necessary to better understand them to extract advantages and disadvantages from each one. Therefore, the objective of this work is the comparison between conventional wells (CW) and IW, using reactive and proactive controls. The first control is simpler to be used and quicker to be optimized but the second type can be more profitable, although more difficult to optimize. The optimization method used to solve the problem is an evolutionary algorithm, which is coupled to a commercial simulator to search for the maximum net present value (NPV), based on the ‘shut in' water cut to determine the optimum time in which to close each valve and the well, in all types of controls. This work employs a model using an inverted five-spot configuration of wells to represent a part of a reservoir under a waterflooding recovery method. Some case studies are used considering different reservoir heterogeneities, type of oil and under economic uncertainty. The conclusion shows that IWs are able to increase production time, oil recovery and the NPV; as a consequence total water production is also increased. The results also show higher benefits in cases with more heterogeneity and light oil. Moreover, IWs using proactive control is better than IWs with reactive control and using either of them is better than CWs.
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.
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.
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.
Gasco operates two NGL plants located in Alexandria; Amerya LPG plant and Western Desert Gas Complex (WDGC). Recently, Gasco has started up a new project that integrates the two plants to maximize Ethane and Propane productivity.
The project design is based on adding new process facilities in Amerya plant to start producing C2+ that directed to WDGC, while a new train is added in WDGC to increase the feed gas capacity and maximize C2+ recovery by applying the Gas
Subcooled Process (GSP) as Ethan mode of operation scheme.
This paper presents a study to increase the productivity of the two plants by using simulation software to help the decision making for what the optimum conditions should be applied in different modes of operation to increase the production.
Qatar Petroleum's super-giant Dukhan field located onshore Qatar has a mature inventory of hundreds of wells. Managing integrity of such mature well inventory to avoid unplanned downtime has been no less crucial than any other activity to
maximizing production and injection. This involves costly wellwork decisions for integrity control and repair, which rely heavily on data obtained from a well integrity monitoring program. Well integrity monitoring program ranges from using basic methods to state-of-the-art downhole monitoring tools. Their applications are almost always associated with limitations that impose uncertainty in well integrity evaluation. This paper presents an integrated approach Qatar Petroleum used to address this issue.
This approach consisted of performing reliability assessment of the entire array of available tools and methods against given well conditions with a matrix of assessment criteria. This matrix enabled selection of a fit-for-purpose set of tools and methods with clear understanding of their strengths and limitations. Techniques of correlation, bracketing and elimination were then applied to analyze the outputs obtained from using the selected set of tools and methods. The approach allowed detecting well integrity problems and determining their severity with minimal uncertainty. The paper focuses on intricacies of the approach, and how its implementation results in a sound well integrity evaluation. It also presents field examples that demonstrate efficacy of the approach in supporting costly wellwork decisions for restoring well integrity. Successfully restoring the well integrity unlocked revenue potential, made quick payout of the wellwork costs and extended the field life.