Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
The Pyrenees Development comprises three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin and are operated by BHP Billiton (Fig. 1). Eighteen subsea wells, including 14 horizontal producers, 3 vertical water disposal wells and 1 gas injection well have been constructed to date and additional wells are planned for infill and to develop additional resources. First oil was achieved during February 2010 and production exceeded 50 million barrels in November 2011.
The Pyrenees fields are low relief, with oil columns of approximately 40 metres within excellent quality reservoirs of the Barrow Group. The 19° API crude has moderate viscosity, low gas / oil ratio (GOR), and a strong emulsion forming tendency which makes oil/water separation and accurate well test metering difficult. Early in the project design phase it was identified that the complex subsea gathering system and the need to reduce measurement uncertainties would dictate special attention to production measurement.
Subsea multiphase flow meters (MPFMs) were specified to meet the challenges of production optimization and allocation while at the same time minimizing production deferral for separator testing. Each oil producer is monitored by a dedicated MPFM. With 14 meters, Pyrenees is among the largest subsea MPFM installations worldwide.
This paper describes the process of MPFM qualification and commissioning together with their performance over 2 years in the field. We show how close cooperation between the Operator and MPFM Vendor has enabled quality rate measurements of emulsified production despite large changes in producing gas/oil ratio and water cut.
While the primary justification for Pyrenees subsea MPFMs was production allocation and optimization, interpretation of transient water cut and GOR data proved valuable for production and reservoir engineering applications. Examples of proactive reservoir and production management including optimizing drawdown of Inflow Control Device (ICD) equipped wells, optimizing well lineup and gas lift to commingled wells are presented.
The first hydraulically operated completion was installed in Australia in 2004 (Guatelli et al 2004). Since then, a number of intelligent completions have been installed in offshore Australia. The remoteness of offshore Australia, particularly in the Timor Sea area, means intervention vessels are not readily available and well interventions are costly operations. For this reason, intelligent completion is considered to be an attractive alternative, by providing a down-hole solution to actively manage the reservoir production life and delay potential water breakthrough.
The Kitan oil field is remotely located in the Joint Petroleum Development Area (JPDA) between East Timor and Australia. The Kitan oil field production facilities consist of three vertical producing wells, subsea flowlines, risers, and one Floating Production Storage and Offloading (FPSO) facility. The wells were completed with an intelligent design and cleaned up using a rig before the FPSO arrived on location.
The intelligent completion design consists of two multi-stage hydraulic down-hole Flow Control Valves (FCVs) and three Down-Hole Gauges (DHGs) to independently control and monitor two different production zones. The FCVs have a total of 8 positions (fully opened, fully closed and 6 intermediate choke positions).
It is planned to close the lower FCV to shut off water production from the lower zone while the upper FCV remains fully opened over the field life. The different FCV choke positions were utilized during the field startup and during the early stages of production while the water cut was still low, to overcome unforeseen technical limitations in the production system, and to optimize hydrocarbon production.
This paper describes various aspects of the Kitan oil field intelligent well completion from design through installation and field startup to early stage of production operations, and includes technical problems encountered during the field startup as well as lessons learnt.
Quinlan, Timothy Michael (Schlumberger) | Sibbit, Alan Matthew (Services Techniques Schlumberger) | Rose, David Alan (Schlumberger) | Brahmakulam, Jacob V. (Schlumberger) | Zhou, Tong (Schlumberger) | Fitzgerald, John Barry (Steve Kimminau Consulting) | Kimminau, Stephen John
Carbon Dioxide (CO2) sequestration and enhanced recovery projects require the evaluation of rocks containing mixtures of CO2, water, and gaseous or liquid hydrocarbons. Pulsed neutron logs of various designs and measurement types have been used since the 1960s to evaluate formations containing gaseous hydrocarbons, but they were not originally designed or characterized specifically for quantitative CO2evaluation. Computer modeling, test pit data, and field examples are presented in this work to highlight the issues of CO2 evaluation and to compare these with gaseous hydrocarbons.
Pulsed neutron tools emit 14 MeV neutrons from an accelerator source, but a wide variety of timing sequences, detector types, source-detector spacings, and signal processing techniques are employed by the industry to extract formation description parameters from the recorded counts. For the non-specialist petroleum engineer this variety can confuse and distract from effective use of the measurements. We organize all categories of pulsed neutron logs into simple types based upon the measurement physics to provide an effective guide to field use of these logs.
Examples of commercial and experimental tools in clastic and carbonate environments are presented. The examples show how CO2 can be quantified and demonstrate critical design requirements for successful pulsed neutron logging campaigns. We outline the lessons learned and make recommendations for the design of logging programs and interpretation of the acquired data in stand-alone or in time-lapse modes.
Marine Bio-Security is a global concern with significant relevance to the off-shore gas and oil production and exploration sector. An avalanche of legislation and regulation is delivering enforceable laws which compel ship owners/operators to adopt prescriptive procedures, protocols and practices to ensure that ballast water is eliminated, or at least substantially reduced as a major vector for the translocation of non-indigenous marine pests (NIMPS). The other main vector for the translocation of NIMPS has been identified as the wetted hull of commercial and military shipping and includes offshore support vessels, mobile offshore drilling units, crew transfer vessels, barges, landing craft and pipe laying vessels. Hull bio-fouling and associated niche areas are presently under the scientific microscope...and will follow the same path in terms of legislation and regulation.
Most offshore wells that require artificial lift are gas lifted, as gas typically is readily available and compared to other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electric submersible pumps (ESPs) can
efficiently and economically increase oil production and reserves recovery under the appropriate operating conditions. This may translate to a lower abandonment pressure in the long term—possibly reducing the total number of wells required to deplete an asset.
Since few ESPs currently are installed in offshore wells, an ESP screening "Rules of Thumb" was created as a simple guide for prioritizing offshore ESP candidates. The selection criteria focus on feasibility of installation, operability conditions
and operating practices to maximize run life, and economic considerations. ExxonMobil† and industry experience from North America, South America, West Africa, Asia, Australia, the Middle East, and the North Sea provided the basis for the study.
Jia, Hu (Southwest Petroleum University) | Yuan, Cheng-dong (Southwest Petroleum University) | Zhang, Yuchuan (Southwest Petroleum University) | Peng, Huan (Southwest Petroleum University) | Zhong, Dong (Southwest Petroleum University) | Zhao, Jinzhou (Southwest Petroleum University)
High-Pressure Air Injection (HPAI) in light oil reservoirs has been proven to be a valuable IOR (Improved Oil Recovery) process and caused more attention worldwide. In this paper, we give an overview of the recent progress of HPAI technique, based on a review of some representative HPAI projects including completed and ongoing projects. Some most important aspects for HPAI field application are discussed in depth, including reservoir screening criterion, recognition of recovery mechanism, laboratory study, numerical simulation, gas breakthrough control, tubing corrosion consideration and safety monitoring. With the successful HPAI application in Zhong Yuan Oil Field in China, it is estimated that foam or polymer gel assisted air injection should continue to grow in the next decade as a derived technology of HPAI for application in high-temperature high-heterogeneity reservoirs. The purpose of this paper is to investigate the ranges of some key parameters, new understanding based on laboratory test and successful field application, thus to provide lessons learnt and best practices for the guideline to achieve high-performance HPAI project.
All oil and gas wells inevitably shifts from asset to liability, whether the result of reaching its economic limit or sustaining irreparable damage. At the end of its life cycle, a subsea well and its supporting infrastructure must be carefully dismantled to
ensure they pose no safety or environmental threats and to salvage useable components. In addition to creating significant safety and environmental hazards, failure to properly abandon a subsea well can lead to a noncompliant status with regulatory
agencies and undermine an operator's image. Despite its multiple liabilities, abandonment offers no real return on investment, underscoring the importance of minimizing cost. The challenge is to retrieve the wellhead without damage so it can be used again, minimizing or eliminating damage not only to the wellhead but also to personnel and environment.
This paper will describe the technological tool system available to retrieve subsea wellheads in a single trip. This technology serves as an alternative to equipment that poses environmental and safety hazards, such as mobile offshore drilling units and explosive severance devices. By latching on to the external profile there is no damage to the internal seals. Also the external latch procedure allows more clearance to allow the cuttings to flow out of the ports and away from the working mechanism. The wellheads retrieved have a much greater chance of being re-used with minimal damage. The external latch design allow for more strength and less chance of tool failure. This paper will also discuss some global case histories.
Today the development of subsea fields or satellites and the remoteness of thelocation not only require subsea processing but have also has implications forthe provision of power. The norm for offshore power generation is the use offossil fuel. However, the uncertainty surrounding a global climate policy at atime when the projection is for an exponential increase in offshore powerdemand is a cause for pause to look at renewable power solutions. Types ofrenewable power solutions that have application to the offshore oil and gasindustry include: solar, wind, and ocean energy (various).
This paper provides a rank/value for offshore power generated with bothrenewable- and conventional- energy sources relative to four (4) projectscenarios: Status Quo, Supply-to-the-Rescue, The Green Agenda, and DoubleJeopardy. The work to select a power solution began by identifying a key focusquestion about the future that the scenarios would address: How will the demandfor offshore (subsea) power and the potential externalities that may resultshape the power generation options over the next decade? The paper also pointsto resources that can shed light on the latest technological advances andfuture trends for renewable energy sources. The hope of the author is that thepaper will prove to be a useful reference for R&D specialists and projectengineers who are often asked to respond to the question: Renewables - Ready orNot?