The subsea operations company said its most recent campaign is the first fully unmanned offshore pipeline inspection completed “over the horizon,” surveying up to 100 km from the shore. One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates. The Norwegian Petroleum Directorate has given clearance to start up facilities at the North Sea field, which straddles the line between the UK and Norwegian sectors. Lundin reports that the hookup and commissioning of installed facilities at the large North Sea field is progressing as planned.
The subsea operations company said its most recent campaign is the first fully unmanned offshore pipeline inspection completed “over the horizon,” surveying up to 100 km from the shore. One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates. The Norwegian Petroleum Directorate has given clearance to start up facilities at the North Sea field, which straddles the line between the UK and Norwegian sectors. Production is set to begin in September.
The West Mira drilling rig was recently constructed in South Korea. Wintershall and Seadrill have announced plans to rely on automated drilling software for a six-well campaign offshore Norway that begins this year. The deal is the latest example of the offshore sector’s slow march toward automated wellbore construction. The operator and drilling contractor plan to install the automation software, developed by Norway-based Sekal, on the newbuild semisubmersible West Mira. The sixth generation rig was designed for harsh weather environments and could start drilling in the Nova field later this year.
The key challenges concerning heavy oil are not associated with finding reserves, but in extracting, producing and transporting heavy crudes. This is even more challenging given the new normal lower oil price. In this presentation, a case study will be presented showing the successful implementation of highly technical modelling techniques in brownfield heavy oil field developments (UKCS).
Infinity's flow assurance and process engineers have been involved in almost all of the heavy oil developments in the UK continental shelf. - Mariner (12-14°API) and Bressay (11°API), Kraken (14°API), Bentley (10-12°API) and Corona (16°API) are some of the examples worth noting.
In the last couple of years the Production Assurance team at infinity have been responsible for the pre-FEED and FEED stages of one of the most important heavy oil fields in the UKCS. Infinity have provided engineering support to several major E&P companies for their heavy oil developments. This paper focusses on the unusual rheological properties, variable Flow Assurance characteristics during production and the most recent modelling approaches to study the behaviour of these challenging fluids. These projects are particularly interesting as they combine the challenge of both heavy oil and brownfield developments.
Key issues for design of heavy oil fields and development of a safe/optimum operating philosophy are addressed and will be shared in this presentation such as: Modelling non-Newtonian fluids with very high viscosities (impact on line sizing); Oil/water dispersion and formation of a stable emulsion; Selection of an artificial lift option and their respective impacts on the behaviour of the system (focus on HSP technology); Operational issues including relatively high restart pressures following an unplanned shutdown (gel formation).
Modelling non-Newtonian fluids with very high viscosities (impact on line sizing);
Oil/water dispersion and formation of a stable emulsion;
Selection of an artificial lift option and their respective impacts on the behaviour of the system (focus on HSP technology);
Operational issues including relatively high restart pressures following an unplanned shutdown (gel formation).
The key challenges with modelling heavy oil were developed and a novel approach to simulation and data benchmarking was developed in order to solve the classic heavy oil modelling issues. As an example, the relationship between shear rate and shear stress in difficult fluids that deviate from the classic Newtonian behaviour demands a very close relationship between the flow assurance engineers modelling the system and the fluid lab experiments required to benchmark the models.
Zhdanov, Michael (University of Utah) | Endo, Masashi (TechnoImaging) | Sunwall, David (TechnoImaging) | Cuma, Martin (TechnoImaging) | Malmberg, Jenny-Ann (PGS Geophysical AS) | Tshering, Tashi (PGS Geophysical AS) | McKay, Allan (PGS Geophysical AS) | Midgley, Jonathan (PGS Geophysical AS)
In this paper we introduce a large-scale 3D inversion technique for towed streamer electromagnetic (EM) data, which incorporates seismic constraints. The inversion algorithm is based on the integral equation (IE) forward modeling and utilizes a re-weighted regularized conjugate gradient method with adaptive regularization to minimize the objective functional. We have also incorporated in the inversion the moving sensitivity domain approach in order to invert the entire large-scale towed streamer EM survey data while keeping the accuracy and reducing the time and memory/storage of the computation. The developed algorithm and software can take into account the constraints based on seismic and well-log data, and provide the inversion guided by these constraints. Application of the developed method to the interpretation of the large-scale towed streamer EM survey data acquired in the Barents Sea demonstrates its practical effectiveness.
Presentation Date: Tuesday, October 18, 2016
Start Time: 3:20:00 PM
Presentation Type: ORAL
The towed streamer EM system makes it possible to collect EM data with a high production rate and over very large survey areas. At the same time, 3D inversion of the towed streamer EM data remains a very challenging problem because of the huge number of transmitter positions of the moving towed streamer EM system, and, correspondingly, the huge number of forward and inverse problems needed to be solved for every transmitter position over the large areas of the survey. We overcome this problem by exploiting the fact that a towed streamer EM system's sensitivity domain is significantly smaller than the area of the towed streamer EM survey. We apply the concept of moving sensitivity domain, originally developed for airborne EM surveys, to the interpretation of marine EM survey data. This makes it possible to invert the entire towed streamer EM surveys with no approximations into high-resolution 3D geoelectrical sea-bottom models. Our implementation is based on the 3D integral equation (IE) method for computing the responses and Fréchet derivatives for 3D anisotropic geoelectrical models. In the framework of the concept of the moving sensitivity domain, for a given transmitter-receiver pair, the EM responses and Fréchet derivatives are computed from a 3D Earth model that encapsulates the towed EM system's sensitivity domain. The Fréchet matrix for the entire 3D Earth model is then constructed as the superposition of Fréchet derivatives from all transmitter-receiver pairs over the entire 3D earth model. This makes large-scale 3D inversion a tractable problem with moderate cluster resources. We present case studies of 3D anisotropic inversion of towed streamer EM data from the Troll West Oil Province and Mariner field in the North Sea.
Towed streamer EM is a recently introduced acquisition system in the class of marine controlled source electromagnetic (mCSEM) technologies. The system architecture emulates 2D seismic with both the source bipole and the receiver streamer in a shallow tow behind the vessel. This facilitates dense subsurface sampling, acquisition speed at 4-5 knots, and it is fully combinable with 2D seismic acquisition at the same time for unprecedented efficiency. The dense data acquisition improves signal-to-noise (S/N), lateral and vertical resolution, and partly mitigates the non-uniqueness issue in the inversion. Previous systems have all been based on stationary recording nodes placed on the seafloor in a sparse line or 3D pattern, and with the source towed close to the seafloor.
Inversion of EM data is a much more computationally intensive process than the inversion of seismic data. Hence 1D and 2.5D inversions have been much more common than full 3D inversion. We have recently introduced cost effective 2.5D anisotropic inversion based on a finite element algorithm, and a highly efficient, comparatively low cost, 3D anisotropic inversion based on the integral equation. The cost savings in the 3D inversion originates in the application of a moving sensitivity domain approach, where the inversion is limited to a subsurface volume surrounding the source and receiver representing the volume that is actually sensitive to the source signal at any particular shot location. The sensitivity domain is then moving with the acquisition system. The Freshét derivatives in the inversion algorthim for the entire domain are then calculated only for the sensitivity domain for each shot, which reduces the computational time and memory consumption significantly. Acquisition is done by means of parallel 2D lines spaced approximately one km apart. This is sufficient data density to create 3D images of the vertical and horizontal resistivity in the subsurface.
Anisotropic inversion is a very important aspect, since the subsurface is always more or less anisotropic. Shales are intrinsically anisotropic and increasingly so with the degree of compaction. Cyclical sand/shale interbedding results in an effective anisotropy, and hydrocarbon-charged high resistivity sands interbedded with shales result in a very high effective anisotropy ratio. There is no accurate isotropic solution to an anisotropic subsurface.
Conventional node-based marine Controlled Source ElectroMagnetics (mCSEM) has considerable limitations in terms of data sampling density with typically 1-3 km between receiver nodes. The acquisition efficiency is also poor with the slow deployment and retrieving of the seafloor nodes, and a source towing speed of 1-2 knots, but surveying can be done in deep water. Towed streamer EM has the advantages of dense data sampling, 4-5 knots speed of acquisition, real-time quality control of source signal and incoming data, and simultaneous acquisition of seismic data. However the shallow tow, that facilitates the high acquisition speed, also means the water depth is limited to 400-500 m or too much signal is absorbed by the water column. The acquisition system is shown in Figure 1 below.
One important challenge working in heavy oil field development is to present a set of production profiles representing low, base and high production without being overly optimistic or pessimistic. The paper give examples on how various methods of assessing the uncertainty in the relative permeability curve shapes changes the view on project uncertainty. Heavy oil laboratory relative permeability experiments face many well-known challenges. The core data is usually unconsolidated with very high permeability. This combined with high viscosity usually leads to unfavourable laboratory conditions like in example capillary end effects and viscous fingering. Typical core issues are fractures, laminations, loose sand, issues with use of multiple core plugs and very low pressure differential at initiation of the experiment. In addition there is always a discussion about reservoir wettability and core history including impact of drilling operations, drilling mud and core depressurization. The total effect is that the laboratory data is often seen as highly unreliable. The challenges are usually solved by using either light oil or by using steady state together with unsteady state experiments. Weaknesses and strength of the steady state method is addressed. Discussion of the alternative methods that is available is given with examples. Can light oil really be used instead of heavy oil given the large compositional differences? What could the impact of asphaltene content be? Examples are given of some typically laboratory effects. A brief discussion is given regarding possible reasons for differences between light and heavy oil behaviour. A benchmark of relative permeability experience from 50 heavy oil fields is presented. The benchmarking methodology is given and explained. Strength and weaknesses of the method is discussed. Actual field data is shown. Examples of relative permeability data used in simulation models are shown. Impact of grid size and properties on relative permeability is shown. Use of rock curves and alternative curve fit methods is presented with weakness and strengths.
The main objective of this paper is to share heavy oil relative permeability observations as seen in laboratory data and as used in reservoir simulatons with focus on history matched mature heavy oil fields. Much of the data is based on a literature screening study including more the 100 heavy oil fields and several hundreds of papers. The remaining data is experience obtained from reservoir evaluation and simulation of several heavy oil field developments as well as experience working with and in special core analysis laboratories. Some of the data is undisclosed but useful information. Hopefully the field experience can be used empirically to give qualitative support in early phase field evaluations with respect to relative permeability input as well as recovery factor estimates. The paper is not to replace laboratory experiements or reservoir simulation studies but only to give qualitiative support. With heavy oil in this paper it is meant oil which may be produced by cold production methods and that has Newtonian viscosities. Typically oil viscosities are between 13 cp and 4 700 cp at reservoir conditions, with a P50 value of 550 cp.
Impact of Relative Permeability on Recovery Factors
Relative permeability is a major uncertainty for commercial decisions in heavy oil field developments. Table 1 presents actual recovery factors simulated with different relative permeability alternatives on a major offshore heavy oil field. The uncertainty in recovery factor was initially from 6% to 33%. The main reason for decrease in recovery is the increase in water production caused by a combination of high water relative permeability end point (K’rw) and a straight Krw curve. The low case scenario was lifted from 6% to 16% recovery factor by evaluation of laboratory data, interpretation of an extended well test and a benchmark with field analogues with respect to recovery factor and relative permeability curves.
Hironori Wasada, senior vice president of JX Nippon Oil & Gas Exploration, highlights the ambitions and challenges facing the domestic and international operations of his company.
What is the current status of the oil and gas industry in Japan?
Japan imports almost 99.6% of its oil requirements, as we produce only 14,000 BOPD, which is less than 0.4% of our consumption. For gas, Japan produces about 3% of its consumption, with 97% of our consumption imported in the form of liquefied natural gas (LNG).
The country is trying to reduce its energy export reliance, and the Japanese government is assisting and encouraging local companies to search for oil and gas offshore. Onshore fields in Japan are old and have started depleting, and recently a Japanese firm made a trial production of shale oil from an onshore oil field. In addition, the government is looking for alternative energy resources to meet growing local demand, and is currently looking at the commerciality of offshore methane hydrates.
Also, several companies recently have been listed on the local stock exchange, which has put the industry under the scrutiny of investors who expect it to deliver revenue.
Who are the major shareholders of JX Nippon? What major projects are you currently involved in?
JX Nippon Oil & Gas Exploration Corporation is a business unit of JX Group, and is engaged in oil and gas development all over the world. We are very active in Japan, where development of local energy resources is the mission of Japanese companies. We are committed to continuing exploration activities in Japan, with the aim of contributing to a stable supply of energy. Currently, we are involved in exploration activities offshore Japan, and this includes the Sanriku and offshore Erimo blocks. Also, we hold a 100% interest in offshore blocks Shikoku, Nishi-kyushu, Sado, and Toyama Bay.
The onshore Nakajo oil and gas field in Niigata Prefecture, Japan, is the domestic E&P base of JX Group. Our mission in the Nakajo field is to steadily supply natural gas to customers, including industries and local communities.
How about investment outside Japan?
NOEX (JX Nippon) currently operates in 14 countries. We are leading projects as operators in crude oil production in Vietnam, natural gas production in Malaysia, and exploration in the UK North Sea. We have also been part of a consortium producing oil in the United Arab Emirates (UAE) for more than 30 years.
We are very active in several Asian countries, including Thailand, Myanmar, Vietnam, Indonesia, and East Timor. In Thailand, we will apply our own experience and technologies acquired through our operations in Vietnam to improve the efficiency of crude oil production at the Nang Nuan oil field in Block B6/27, where we hold a 40% interest with PTTEP Siam, the operator with a 60% interest in the field. In Vietnam, we are involved in Block 15-2, Block 05-1 b/c, and Block 16-2, while in Myanmar, we hold interests in Blocks M12, 13, and 14 and Block M11.
We are also involved in LNG projects, including the Tangguh LNG project in Indonesia, and Papua New Guinea’s first LNG project, which is set to deliver its first LNG cargo in 2014.
Mariner is a large heavy oil discovery in block UK-9/11, located 320 km north east of Aberdeen. The execution and development of the project will be from Statoil's new Aberdeen office. The discovery contains 1-2 Billion Barrels of Oil in Place in two reservoirs (Maureen and Heimdal). 19 appraisal wells have been drilled. The oil viscosities are 67 cp (Maureen) to 508 cp (Heimdal) at reservoir conditions. Production start is in February 2017. The reservoir development is based on use of re-injected produced water. ESP pumps are used for artificial lift. In total 100 wells are planned including multilateral slanted wells and horizontal wells. Two drilling rigs and one work-over rig will be active in parallel the first 4 years. Challenges to be met are related to high oil viscosity which gives early water breakthrough and mapping of remobilized Heimdal channel sands. The available seismic only allows for a stochastic Heimdal reservoir model. A full field broadband seismic survey will be available in 2013, applying the newest advances in technology to aim at better imaging the Heimdal sands. Current development strategy for the Heimdal reservoir is pattern drilling using an inverted 9-spot pattern. The work going forward will focus on use of the new seismic data to establish a deterministic reservoir model to be used for well planning. Work is on-going to significantly optimize the Heimdal development. Active geosteering will be important to limit the use of pilot holes and improve Heimdal reservoir sand mapping. The reservoir simulation model is very computer time consuming. Coupled segment models have been constructed that replicates the full field simulation but with significant reduction in simulation time. A polymer flooding study has been initiated to realize the EOR potential.