CO2 can be an effective EOR agent and is the dominant anthropogenic greenhouse gas driving global warming. Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future, by adding value through EOR production and field life extension, and providing long term secure storage post-EOR operations.
Shell is working to implement new generation CO2 projects, including offshore applications. Based on recent offshore project design experience, this paper describes the challenges in moving CO2 EOR from onshore to offshore and the solutions developed, in the key areas of safety, facilities, wells, subsurface and piloting. The overriding design principle in any project is HSE. Offshore operations brings a new set of challenges over inventory, pressure, confined spaces and evacuation, with conventional emergency procedures requiring modification because of the different physical characteristics of CO2 releases compared to hydrocarbon gas. Surface facilities need to be simple to minimise CAPEX, weight and space while maintaining flexibility, since there is less scope to incrementally evolve the surface facilities as is the case onshore. Balancing the tension between these objectives requires very close surface and subsurface integration to find optimal and cost-effective solutions.
This is illustrated with three key decision areas: gas treatment options for back produced CO2 and hydrocarbon gas, artificial lift and facilities capacity.
A novel integrated CO2 gas lift system is described. This simplifies facilities and reduces CAPEX and OPEX, while at the same time providing a high degree of flexibility and risk management over the EOR life cycle in terms of subsurface uncertainty and reducing the issues around molecular weight variation in the recycled gas and the degree of turndown required in the facilities in the early years of EOR operations.
Development of U.S. shale plays has greatly accelerated throughout the past decade and will continue to contribute increased production of gas and hydrocarbon liquids for many years to come. A March report by HIS-Cambridge Energy Research Associates estimates that in 2000, shale gas was only 1% of total production in the U.S., but it now makes up approximately 20% of the total production with the potential to contribute greater than 50% by 2035. The two main technologies attributed with the successful growth in shale-play development are horizontal drilling and fracturing technologies.
Coiled-tubing (CT) equipment and technologies have also aided in the rapid and economical development of shale plays. The demand for these services has increased such that a CT unit is now assigned to each frac crew. Because of CT's capability to continuously circulate, work with live-well pressure, and push to the toe of long, horizontal sections, several tools and methods have been devised to transfer these advantages to stimulation and well-servicing solutions to help optimize production while minimizing time and cost. These technologies include hydrajet and CT-conveyed perforating techniques as well as accurate placement of stimulation treatments with precise and instantaneous proppant-concentration control. Larger CT sizes are being used to enhance treatment rates, service longer horizontals, and provide additional weight or force at the end of the tubing for plug drillouts or manipulating service tools. The trend in longer and larger CT size is also driving the need to optimize the CT unit design to maintain operational efficiency and safety as well as meet Department of Transportation (DOT) regulations. This paper reviews these new CT techniques and trends being used to improve shale play developments with case histories.
The successes demonstrated in the U.S. are now being targeted at shale-play developments in the eastern hemisphere and Latin America to meet their growing demand for clean and economical energy.
With most of the world's largest and easiest-to-exploit deepwater oil reservoirs already under development or producing, the industry is now facing new deep offshore challenges: the production of smaller fields that often contain more difficult oils.
The tie-back of new fields to existing facilities can be a viable method for developing such marginal offshore fields, which are often too small to be developed economically on their own.
The use of subsea processing and innovative field architectures as development solutions is fast becoming a reality. Such challenges are already being addressed in the development of certain fields in the Gulf of Mexico (King, Perdido...), Brazil (Marlim, BC- 10…) and the Gulf of Guinea (Pazflor). However, long subsea tie-backs come with inherent complications.
The most demanding are the flow assurance issues arising from the different operating regimes, and these may be combined with more viscous fluids and/or reservoirs at low pressure or low temperature.
This paper examines the advantages and limitations of various field architectures that may be considered for long satellite tie-back lengths in deep waters.
The first part addresses production considerations such as turndown, preservation and restart management for each candidate architecture. The impact of tie-back length on operating modes is also evaluated. The second part examines the impact of these operating modes on the receiving facilities.
The purpose of reservoir modeling is not only to build a model that is consistent with currently available data, but also to build one that gives a good prediction of its future behaviour. Updating a reservoir model to behave as closely as possible to the real reservoir is called history matching, and the estimation of reservoir properties using this method is known as parameter estimation and it is an inversion process.
Here we apply one of the evolutionary algorithms (Particle Swarm Optimization - PSO) to estimate porosity and permeability using both production and 4D seismic data. PSO is a population-based stochastic optimization algorithm. It is known as a swarm intelligence algorithm because it was originally inspired by simulations of the social behaviour of a flock of birds. The method combines simplicity in implementation and high capability for distributed (parallel) computing.
The results obtained on a 2D section of the Norne Field in the Norwegian Sea, demonstrate that this parameter estimation approach combines moderate computational requirements and better objective function values and exhibits good ability to handle history matching problems without exhaustive sampling of parameter space.
The Dunbar Field (UKCS, Block 3/14a), operated by Total E&P UK, is situated on an intermediate terrace between the East Shetland Platform and the Viking Graben and characterised by a series of pre-Cretaceous and structurally aligned tilted fault blocks. The principal hydrocarbon accumulations are contained in the Middle Jurassic Brent Group and younger Upper Jurassic Heather Sands.
Internally, the field is compartmentalised by a number of N-S faults and a secondary alignment of NE-SW faults which cross cut and often offset the main N-S faults. The larger scale faults down throw to the east and subdivide the field into four main areas; the West Flank, Central Panel and Frontal Panel with an uplifted Horst (Triassic) Panel in the south. Each of these panels has specific reservoir and fluid characteristics.
The Central and Frontal panels have a substantial production history of 15 years. The field is in steep decline with high water cut in water flooded areas, and extremely low pressure in compartments produced by natural depletion. A better understanding of recovery from the main flow units is essential for estimation of drainage volume, optimisation of water injection pattern and infill well placement/completion.
The ability to better define the size of the connected volumes through improved fault identification (Seismic PSDM3D Reprocessing) along with an improved understanding of the permeability field (sedimentological, petrographic, XRD, SEM, SrRSA, DST analysis & simulation studies) has been key in assessing Dunbar's future potential. An intensive data acquisition campaign has been integrated in a comprehensive dynamic synthesis leading to a reservoir model history match that has improved our understanding of the field.
This paper describes the multidisciplinary team work leading to an improved understanding of the recovery efficiency and reservoir connectivity leading to a further drilling campaign.
In 2010, the operator completed the successful replacement of a damaged fairlead within the mooring system of its FPSO (Floating Production, Storage and Offloading). This is believed to be the first time that a fairlead has been changed-out in situ on any floating installation in the North Sea. This was a complex operation involving many different vessels and topsides activities. This paper details how the damaged fairlead was safely secured and replaced.
The replaced fairlead was deemed irreparable because one of the axle retaining plates and its associated bolts were missing. However, after further ROV (Remotely Operated Vehicle) inspections, it was discovered that the remaining seven fairleads were also displaying symptoms of the same failure mode i.e. axle retaining bolts were missing or found loose placing further strain on the remaining bolts.
The condition of the axle retaining bolts was deteriorating and the operator was unsure when the next catastrophic failure could occur. Therefore, ROVs were used to secure the seven failreads as effectively as possible by replacing/ tightening bolts and air divers were mobilized to install pins to apply additional clamping
force while allowing access to the original retaining bolts. The original bolts were replaced and segregated so that they could be analysed onshore.
An investigation was undertaken to understand the failure mode of the FPSO fairleads. It was hoped to compare the differing levels of damage to different factors such as weather, mooring line catenaries, etc… to determine which factors are significant.
It was concluded that the bolt damage was mainly the result of design issues. A combination of QA/QC (quality assurance/ quality control) issues, environmental and operating conditions could explain the differing levels of fairlead damage.
The integrity of the mooring system was severely under threat throughout. Plus, replacing a fairlead is a long and costly exercise, therefore early identification of fairlead bolt issues and intervention is extremely valuable.
In October 2010 the deepest set sealed multilateral junction in the industry was installed at 6900 m MD in Oseberg South well 30/9-F-9 AY1/Y2.
The differential pressure across the junction in the well is expected to be in the range of 250 bars. To meet this pressure requirement, a multilateral (ML) junction rated to 370 bars was identified. The high pressure junction components and entire multilateral system has undergone an extensive testing and qualification program, including several component tests and a full scale system interface and integration test.
A 10 ¾" pre-cut window with an outer aluminium tube was installed as an integral part of the 10 ¾?? liner. The plan was to perform the milling operation through this window. A stuck string incident during the 10 ¾?? liner installations accidentally caused the liner to drop in hole. The liner ended up at the wrong orientation, and the window could consequently not be used.
The mainbore was drilled to TD at 8583 m MD and the 7?? liner was run and cemented. After the liner perforation the MLT operations started with the installation of a multilateral anchor packer to allow for installation of a latch interface assembly (LIA) and milling system. The LIA was installed and locked into the multilateral packer on a separate run.
The milling operation was done in a two step operation with milling of a 1st pass window using a 10 ¾?? milling machine prior to installation of whipstock and performing the 2nd pass milling operation.
The lateral branch was drilled to TD at 8258 m MD and a 5 ½?? screen completion was run and dropped off into the 8 ½?? open hole. The drilling whipstock was retrieved from the well and a completion deflector was installed. The junction was finally stung into the deflector, simultaneously as an open hole seal
stinger entered top of the screen liner in open hole, tying the branches together.
A 6900 m long upper completion string with inflow control valves was finally installed to allow for surface control of the two branches.
Introduction to the Oseberg South Field
The Oseberg South platform is located in the North Sea, 130 km west of Bergen, Norway (Ref fig 1). The platform commenced production in the fall of 2000. The Oseberg South field, consisting of several geological structures south of the Oseberg main field, is developed with an integrated drilling, accommodation and production platform on a steel jacket. There are 32 wells planned from the platform. Oseberg South field's plateau production is app. 5400 m3 (34 000 barrels) per day. Sea depth is about 100 meters. The oil is transported via the Oseberg Field Centre and Oseberg transport system to the Sture terminal.
Well 30/9-F-9 Y1/Y2 was planned to target Upper Tarbert (UT) and Middle Tarbert (MT) at the G-Central structure. The well was planned as the first oil producer, and the target area is located in the southern parts of the structure (Ref fig 2). The well was planned as a MLT well where the first branch (Y1) will produce Upper Tarbert oil/gas and the second branch (Y2) Middle Tarbert oil.
Upper Tarbert contains about 70% of the expected oil and gas reserves and generally consists of wave-reworked lower-upper shoreface siltstones and fine-grained sandstones with relatively poor reservoir properties (average values for porosity and permeability are typically in the order of 5-18 % and 0.2-20 mD, respectively). Upper Tarbert deposits have high degree of variability, from high gamma ray sands and silts to very tight calcite cemented stringers.
In general the Middle Tarbert Formation is sub-divided into two parts: MT1 and MT2. MT1 is interpreted as near shore deposits while MT2 was deposited in a more energetic tidal environment. The porosity is within the range 12-26 % while the permeability varies from 50 - 2500 mD.
Routine testing of wells with electric submersible pumps (ESPs) is usually conducted monthly to monitor liquid rates, water cut (WC), and gas/oil ratio (GOR). This monthly testing is the most common form of production and reservoir surveillance and is implemented in even the most mature fields where cost control generally takes precedence over reservoir surveillance.
However, this technique has its limitations. The most common limitation is insufficient testing duration to capture a representative sample of reservoir fluids. This testing duration issue is often the case in low-flow rate and deep wells, which require several time-consuming whole or complete liquid holdup periods. Other potential problems include insufficient resolution or repeatability to identify trends in liquid and water-cut rates over short periods of time. To date, the only method
for resolving these issues has been to install permanent multiphase meters on each well. Although this method has been implemented in some fields, it is uneconomical for most wells. An analytical method is described for a flow rate calculation that can be implemented in wells produced with ESPs and equipped with downhole gauges and real-time monitoring systems.
These downhole gauges and real-time monitoring system provide continuous real-time virtual flow rate measurements and therefore, both liquid and water-cut trends, which deliver the required resolution and repeatability to support both well performance diagnostics and near-wellbore reservoir analysis. This technique, which has the advantage of being valid for both transient and steady-state conditions, provides instantaneous flow rate data when used with real-time data. Case studies presented will illustrate model calibration and its application to back allocation and transient analysis. Examples are provided to show how the data can be used to rapidly identify changes in productivity index and reservoir pressure across the drainage area; thereby, enabling real-time production optimization.
Recent incidents have highlighted the increased importance of situation awareness and its relationship to crisis management, With studies showing some 40% of incidents being related to operational error the need for an effective process safety management (PSM) framework which melds procedural automation with a previously IT centric business process management (BPM) environment could be seen to be advantageous. The final hurdle to a fully integrated solution has been the capturing of stranded assets e.g. where data collection is not possible, consistency of timely manual information or a heavy reliance on experienced human elements to consider information context.
The realization that an "Incident free?? mission statement can effectively drive business strategy when used in conjunction with a mobile workforce is acknowledged. When used as part of an operator driven reliability program, we have a solution which captures tacit knowledge, improves inter-departmental collaboration and enables sensor to boardroom visibility. This Enterprise Control model enables the right people to consistently do the right thing optimally planned within the operational schedule.
This paper will describe how technology can be used as a change agent, not only to enable the consistent monitoring of previously stranded assets (People, Plant & Processes) but to change the workflow dynamics of the PSM model with field proven improvements in Safety and Productivity.
With some predicting the passing of peak oil production & with an expected additional 20MM bpd of oil products being required over the next 15yrs, primarily driven by emerging market growth. The need for exploration and production in challenging environments is not going to go away. These challenges include deep water drilling, unconventional gas, requirements for high local employment content and areas of environmental importance.
With a continuation of low probability / High Impact events affecting the Industry, the loss of trust from stakeholders (Employees, Society, Government & non governmental agencies) has raised the importance of transparency and stakeholder engagement. Prior to Macondo it should be remembers that the oil industry had successfully drilled some 14,000 wells without incident, however the loss of trust means that organizations are no longer trusted to find the best technology solution to problems and to get on with implementing them. The response requires a step change in transparency and stakeholder engagement. As trust has diminished the demand for partnerships with stakeholders for open reporting and external assurance (Show Me) has increased.
Enhanced oil recovery methods for heavy oil are growing at a fast pace. In Canada alone, approximately 53% of the nation's crude oil production (~2.8 MMBbl/day) comes from Alberta's Oil Sands. Remote sensing and monitoring technologies developed for thermal methods are providing the industry with an immense amount of data that will aid in the improvement and optimization of production performance. This paper details how to integrate seismic, tiltmeter, temperature observation well data with field production data, first with simple surveillance techniques, then with flow simulation. Currently, heavy oil is experiencing significant growth in reserves whereas conventional light oil reserves are essentially fully tapped and are diminishing. Heavy oil is becoming key to meeting growing energy demands worldwide.
Current analytical approaches to heavy oil reservoir studies are too general, and tend to not include rich surveillance data such as seismic, temperature and pressure. This general approach over-simplifies the dynamics present in these reservoirs and does not give an accurate depiction of behavior and performance estimation. On the other hand large simulation studies can be cumbersome and not adaptive to new surveillance data. This paper focuses on a hybrid approach to analyzing various heavy oil fields in Canada, and outlines newly developed surveillance methods which better characterize heavy oil reservoirs.
These field cases include geological data, pressure readings, seismic analysis, temperature observations, and historical production, all of which are used to enable the optimization of field production.
The proposed analytical techniques allow for a more precise estimate of recovery and sweep efficiency so that an efficient optimization strategy can be developed. Applying these analytical techniques to the Surmont and Christina Lake projects in the Athabasca area has given particularly important insight into SAGD steam chamber development and has shown to accurately estimate steam chamber volume and shape.
When seismic and temperature data is used to estimate steam chamber volume there is strong correlation to produced volumes and shows that displacement efficiency is a time dependant variable and increases with steam chamber maturity, initially ranging only 20-30% and approaches 60-70% with time. These results also indicate that effective drainage of established steam chamber volumes takes about 2-4 years.
Displacement efficiency has shown to be a critical factor in controlling recovery from the steam chamber and although increased volumetric sweep is beneficial, this paper has shown that the rate at which it grows greatly affects the rate at which the displacement efficiency increases in the steam chamber. Increasing the volume of the steam chamber too quickly can potentially decrease the effectiveness of SAGD because it tends to introduce many unstable chamber characteristics and develop new significant heat losses.
Simulation has shown that heterogeneity can in fact aid in the SAGD process but controlling steam chamber uniformity and development in heterogeneous reservoirs becomes much more difficult. The vertical barriers, if monitored closely, can help in dampening the rate of steam chamber growth ensuring that residual oil saturation in the established chamber volume is at its lowest before new energy routes are introduced.