Dhote, Prashant (Kuwait Oil Company) | Al-Adwani, Talal (Kuwait Oil Company) | Al-Bahar, Mohammad (Kuwait Oil Company) | Al-Otaibi, Ahmad (Kuwait Oil Company) | Chakraborty, Subrata (Schlumberger) | Stojic, Slobodan (Schlumberger)
Subsurface petroleum industry is burdened with uncertainties in every aspect from exploration to production due to limitations of accessibility to reservoir and technology. The most important tools used to understand, quantify and mitigate the uncertainties are geostatistical static modeling and numerical dynamic simulation geomodels. Geomodels are widely used in the industry for characterizing the reservoir and planning favorable development strategy. It is vital instrument for maximizing asset value and optimize project economics.
Static geomodels are foundation for all the advanced numerical and analytical solutions to solve the intricacies of reservoir performance. At the same time, it is where all the static and dynamic geological and engineering observations get integrated to develop common understanding of the reservoir for future studies. Understanding of the above observations and imaging of reservoir framework by individual is the basis for building static geomodels. Hence, at time, the process is highly subjective and proper QC'ing of the models to achieve the general and specific modeling objectives becomes imperative. Simple Questionaries’ based QC'ing and ranking methodologies are also controlled by subjectivity and individual preferences.
In the present endeavor, quantitative ‘Key Performance Indicators (KPIs)’ based standard static geomodeling practices and QC'ing methodologies at corporate level are developed in specially designed "Process Implementation Project (PIP) – Hydrocarbon resource and Uncertainty Management"’ under the aegis of ‘Kuwait Oil Company (KOC) - Reservoir Management Best Practices Steering Committee'.
The main objectives are to establish a practical modeling process, workflows and criteria to standardize modeling processes. A structured self-guidling modeling document has been developed with self-assemment guidelines and questionary. Finally, for each individual process a set of KPIs are specified as minimum standard to meet to obtain the approval of static model.
The present efforts are important for any geologists, geomodelers and reservoir engineers dealing with geostatistical and numerical reservoir modeling and will provide the KPI's based general practices for quality assurance (QA) and QC'ing of the models.
Inhibitor injection is probably the most popular option for avoiding gas hydrate problems. However, inhibitor injection rates are normally designed based on worst operating conditions (i.e., maximum pressure and minimum temperature) with significant safety margin (e.g., 3-5 °C). Although the system pressure normally drops with time, the injection rates are not normally changed. Furthermore, large quantities of inhibitors are used during start-ups and maintained until the system conditions at monitoring point is well outside the hydrate stability zone. This is completely understandable considering the costs and risks associated with hydrate blockage which outweigh any savings associated with reducing inhibitor injection rates.
However, high inhibitor injection rates are not sustainable later in the life of the reservoir when the water cut increases, hence there is significant interest in developing monitoring and warning systems that can adjust inhibitor injection rates and warn against any potential hydrate blockage.
This laboratory has been investigating various techniques for monitoring hydrate safety margin and detecting early signs of hydrate formation for a number of years through several JIPs. After screening many techniques we have developed two main techniques for monitoring hydrate safety margin (i.e., how far the system is outside the hydrate stability zone) and detecting early signs of hydrate formation. The techniques have now been tested and implemented in many places around the world. These techniques enable us to adjust inhibitor injection rates based on system parameters, hence a more reliable and cost effective hydrate prevention strategy. In this communication we will present the developed techniques and some of the case studies.
Injection of hydrate inhibitors is the most common measure to prevent hydrate blockages apart from dehydration and thermal insulation (including heating). There are three types of hydrate inhibitors in terms of inhibition mechanisms, including thermodynamic hydrate inhibitors (THIs), kinetic hydrate inhibitors (KHIs), and anti-agglomerants (AAs). THIs inhibit hydrate formation by shifting the hydrate phase boundary to lower temperature and higher pressure, moving the operation conditions outside the hydrate stability zone (HSZ), while KHIs do not prevent hydrate formation but delay hydrate nucleation and hinder hydrate crystal growth within a certain degree of subcooling, which allows the hydrocarbon fluids sufficient time to pass through the length of a transport pipeline where the thermodynamic conditions are inside the HSZ [1-5]. Contrary to THIs and KHIs, AAs allow hydrate formation but prevent individual hydrate crystals from agglomerating together, therefore, maintain the hydrocarbon system transportable [5, 6].
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Hydrocarbon, Economics, and Evaluation Symposium held in Calgary, Alberta, Canada, 24-25 September 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The perception of natural gas today is radically different from what it was 10 years ago. Years ago, the natural gas was perceived as a noble fuel, reserved for premium uses. Today, it is used in a variety of sectors and applications and is experiencing significant growth as a fuel for electricity generation. During the years 1990-1997, twenty six countries around the world introduced the participation of private capital in the natural gas transmission. The major participation of private capital has been located in Latin America and Caribbean countries. Argentina, Peru and Colombia have undertaken the most ambitious privatization efforts.