The Viking formation in Western Saskatchewan and East to Central Alberta is comprised of many different oil pools. These plays have seen resurgence in activity over the last 6 years as a result of the horizontal multi-stage fracturing revolution. A wide variety of fracturing technologies have been applied, encompassing open versus cased hole, variable proppant tonnage per stage and fracture spacing along the wellbore. How does the average company make meaningful decisions as to how to stimulate their wells? There is a need to make sense of the production response of the wells given reservoir quality differences, primarily permeability variation, and the variety of fracturing technologies being applied. The paper will develop a workflow which integrates publically available production data to first identify a production rate metric. This metric can be used for production forecasting and as a basis to compare area and pool production performance. Combining this information with well ownership leads to a preliminary assessment of whether production success is due solely to the reservoir, or the drilling and completion strategy applied.
The field was developed in a deepwater setting by Woodside Energy Ltd (WEL) and Mitsui E&P Australia Pty Ltd and commenced production in 2008. The field is located some 50 km offshore Western Australia, in approximately 400m water depth. Similar to other projects in the area, the development of the field was based on a subsea tieback to an Floating Production Storage and Offtake vessel (FPSO). The artificial lift for the field was based on the deployment of a subsea multiphase boosting system, to ensure satisfactory production rates and recovery of hydrocarbons.
This paper will address the typical applications and characteristics for subsea multiphase boosting systems, and provide an overview of the system deployed, as well as the drivers for selecting this technology. The benefits to the users are normally related to reduced investments, and more importantly, increased recovery and optimum utilization of hydrocarbons in place. The potential extension of field life for producing assets through multiphase boosting may have significant impact on the overall economics of the development.
The operational experience of the subsea boosting system will be discussed, including the performance of the subsea boosting system. The operation of the boosting system is based on the concept of integrated operations, and thus the performance of the subsea pumps and all auxiliaries are condition monitored on a real-time basis. The experience and added value generated through integrated operations of subsea rotating machinery will be discussed, including the potential upside with regards to system availability and maintenance.
Based on the successful deployment of a subsea multiphase boosting system the operator gained experience with the operation of subsea rotating machinery and production boosting. It is the objective of this paper to share considerations, advantages and future expectations of the technology, and put forward recommendations for future deployments of the same.
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 This paper presents an overview of the processes, design and technology choices behind taking the latest multiphase meter (with new measurement, visualization and tomographic techniques) subsea. The paper will look at applications for the new meter and the benefits of designing a subsea version.
Analysis of field performance is a critical step in improving the production efficiency and optimizing the cost of operations. However, existing methodologies of analysis have limitations, particularly in the size of the analysis set and the inability to compare different types of assets. The new methodology was designed to overcome these limitations.
This paper explains the methodology of field performance assessment and shares some high-level results of the analysis. Operational performance is compared with results within a peer group. It allows the operator to obtain insightful information on how to improve the efficiency and reliability of production operations. The methodology is characterized by high quality performance indicators - the large amounts of data were collected from the operators and public sources, including cost, production, and technical field data. The detailed analysis is conducted for 12 standard operating cost classifications across seven oil and two gas peer groups, based on similar geological and operational characteristics. The methodology focuses on operations cost performance, production efficiency and production reliability performance, efficiency and cost driver analysis, and gives a suggested action plan. The paper also demonstrates how the results may be utilized to improve efforts by operators in the environment of mature oil fields with declining production levels.
The described methodology was applied to an analysis of the Permian Basin, which contains a large number of maturing oil fields. The study assessed 90 fields, including 35 waterfloods, 20 primary, 15 tertiary, and 20 gas fields for the period of mid-year 2010 to mid-year 2011. Trends and correlations between production efficiency and cost driver factors were found. This led to the issuing of recommendations to the producers.
The proposed methodology can be applied to an analysis of the operations performance of mature oilfields in Russia, which will result in low operating costs and higher production volumes.
Copyright 2012, IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition This paper was prepared for presentation at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibitionheld in Tianjin, China, 9-11 July 2012. This paper was selected for presentation by an IADC/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 International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or 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 International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited.
In-well flow measurement remains as one of the most difficult tasks in the oil and gas industry, mainly due to the challenging conditions of the downhole environment. When made successfully, however, it plays a major role in monitoring and optimizing well performance, especially for the wells equipped with advanced completion devices. The increasing demand for in-well flow measurement is also driven by other factors including zonal production allocation in multizone completions as well as reliable commingled production, reduction of surface well tests and facilities, and detection of production anomalies.
This paper provides a closer look at one of the state-of-art in-well flow measurement technologies: optical, strain-based, phase flow rate measurements via turbulent structure velocity and sound speed of the turbulent flow. It is an introduction to how this flow measurement technology works and how it is applied to different flow applications from single-phase injectors to multiphase producers. Specific field examples representing different flow applications are also referenced to published material. The strong and weak points of the technology are explored, and in the process, an operation envelope is produced for the use of this technology. The system response to the presence of advanced completion devices are also discussed, guidelines are given, and recommendations are made based on field and lab tests.
Understanding a technology's strong and weak points before implementation is essential to ensuring that informed and successful decisions can be made concerning its use for a given application. This process is often mutually beneficial to both operators and equipment manufacturers since collaborations can lead to advancement of technology and, as a result, provide even more reliable solutions.
The use of the phrase "intelligent well?? was not common a decade ago. The reason is hidden in its definition. Because we are engineers and not linguists, our definition can be based on what we would like to achieve in using that phrase: An intelligent well should typically have sensors downhole to measure flow properties including pressure (P), temperature (T), flow rates, phase information such as gas volume fraction (GVF), water-in-liquid ratio (WLR), and perhaps more. It should also be possible to control and optimize the well production by means of adjustable chokes on the surface and in the well, so that an even flow distribution can be achieved particularly in multizone applications with the end result being more efficient production and longer lifetime of the well. Most of these complex, state-of-art devices were not available not too long ago. This has changed thanks to the technological advancements, and today we can manage wells more "intelligently??.
The pump recirculation loop is a key component of the seabed boosting system toensure successful operation and to enhance field production. The designrequirements, methodology, and summary of results of the flow assuranceanalysis performed on a subsea pump recirculation system are summarized in thispaper. The analysis includes the sizing of the pump recycle line and recyclechoke valve; detailed thermo-hydraulic modeling of steady state and transientpump operations including normal, start-up, and shutdown; and the developmentof the hydrate management plan for the pump recirculation system. Thesimulation models developed as part of this analysis are used to assistengineers and operators in evaluating field production and pump performanceoperating limits. In addition, they are used to determine pump system operatingset points and to develop/validate operating procedures. Once the pump systemsare brought online, these models should be benchmarked against field operatingdata and could be used to support surveillance/ monitoring, productionoptimization, and to avoid/ mitigate potential flow assurance problems.
Purpose of Recycle Loop
The primary purpose of the recycle loop is to allow the pump system to operatewithin the operator's preferred pump operating window during conditionsinvolving low field production flow rates. The minimum preferred pump flowrates would be 5500 bpd at 40 Hz (pump speed), 7000 bpd at 50 Hz, and 8800 bpdat 60 Hz, respectively.The secondary purpose of the recycle loop is to minimizepump discharge temperature, which is limited to 250°F. The recycle loop isintended to be primarily un-insulated to allow heat transfer with ambientseawater.
Steady State Analysis
Modeling Inputs and Assumptions
Inputs used in this study were:
1. Reservoir pressures in the range of 11,000 to 15,000 psi
2. Reservoir productivity index in the range of 0.5 to 2 stb/d/psi
3. Reservoir temperature of 250°F Water cut range of 0-20%.
4. Gas volume fraction (GVF) at pump suction of 0 - 10%
5. The seabed ambient seawater temperature is assumed to be 40°F
6. The ambient seawater velocity is assumed to be 0 ft/s
Modeling constraints were:
1. Steady-state individual well production flow of 3000 to 10,000 bpd
2. Minimum allowed flowing bottomhole pressure (FBHP) of 8000 psig
3. Minimum pump suction pressure of 1400 psig
4. Maximum reservoir drawdown rate would be 1000 psi/hr
5. Topsides pressure of 250 psia
A miniature sensing technology can be used inside pipeline maintenance pigs ofany size and configuration in order to measure fluid conditions, map pipelinefeatures, and identify potential wall buildup or defects. The miniature sensorcan be used in pipelines where conventional in-line-inspection tools cannottraverse, while significantly reducing deployment cost and risk. It can also beused to provide near real-time monitoring of critical pipeline characteristics.The pill-shaped housing containing the sensing elements can collect data onmultiple variables, including but not limited to, pressure, temperature, 3-axistilt, and acceleration. Multiple tests were conducted using the technologymounted onto pigs in a 12-inch flow loop with single-phase gas and liquidmedia. Results from the sensing device consistently identified known bends andwall-thickness changes as small as 0.125 inches. The sensor pill device wasalso deployed in a free-floating arrangement without a carrier pig in the flowloop filled with water. This design enabled the sensing device to travel thelength of the line without a pig, thus indicating a potential inspectionsolution for fully unpiggable pipelines.
Copyright 2012, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 30 April-3 May 2012. This paper was selected for presentation by an OTC 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 Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited.
In the oil & gas industry sporadic studies are developed to analyse the flow conditions and operations procedures through the life of the field. The objective of those studies is to understand the environment, boundary conditions and properties changes along the fluid journey. For characterization of the production behavior, engineers use model-based multiphase flow simulation via various applications available on the market.
A constant understanding of the fluid flow conditions is valuable for the decision process on the execution of operational procedures. A robust flow assurance strategy is dependent on the level of awareness of the real production conditions prior to a fluid flow interruption event. Fiber optics distributed sensor system has been recently used mainly for integrity monitoring purposes; the proposed methodology unlocks the additional values for interfacing disciplines as flow assurance by the provided simultaneous distributed measurements of temperature, strain, and vibration.
The model-based multiphase flow simulations represent flowlines and production networks and as output of those simulations operating profiles are used to evaluate the risk of solids precipitation and deposition along the flow path. A regular update of simulation models by real-time data from field sensor results in a more reliable representation of the production system operating profile that can support the flow assurance strategy by the detection, monitoring, and location of events.
This paper proposes the use of real-time data acquisition from an optical-fiber distributed sensor for the assurance of fluid flow along the production system. It outlines a methodology to perform flow assurance automated surveillance based on multiphase flow simulation models constantly fed with real-time field measurements to estimate fluid flow conditions throughout the system to avoid potential problems, such as flow restrictions due to solids deposition.
Introduction to Flow Assurance
Flow assurance is a broad discipline dealing most notably with the solids deposition issues of hydrate, wax and asphaltene. In fact it can be considered to encompass fluid-equipment interactions from sandface to receiving facility and beyond to export. Thus it can be considered to also include challenges such as: multiphase flows (especially slug flow), internal corrosion, emulsions and scale.
Some success has been realized in the past through a combination of limited flow assurance analyses and over-design to compensate for the attendant uncertainties. Operational difficulties and excessive operating costs as a result of poor system design (or as a result of over-zealous capital cost control) have also been quite common. However, the current state of the art is to try to reduce both over-design and short-sighted design, and work towards a production system truly optimized from first oil through to abandonment.