EOR – Enhanced Oil Recovery
There are two phases involved with the extraction of oil from reservoirs that are employed as the extraction develops. Primary recovery leads to a natural depletion of the reservoir. In order to aid oil, recovery water is pumped to sweep oil and also to maintain reservoir pressure, this is the ‘second recovery’ phase of the operation. If water injection fails to recover all the oil reserves ‘tertiary recovery’ techniques are employed to harvest the remaining deposits.
We have successfully implemented EOR extract using hydrocarbon miscible gas, the team is currently working towards employing new EOR technology, such as low salinity.
EOR development is not without its technical drilling challenges. There are considerations concerning our existing infrastructure, with certain facilities requiring significant upgrades. However, the development of EOR capabilities will help prolong the shelf life of the company.
EOR – Hydrocarbon Miscible Gas
EOR using hydrocarbon miscible gas is an interesting technical development as the gas associated with oil production can be re-injected.
Our reservoir is the ideal depth to apply effective hydrocarbon miscible gas injection. In addition, the size of the reservoir combined with the quality of the rock allows extensive oil recovery. The oil quality – light – ensures miscibility with the associated gas. Based on the favourable vertical and horizontal conditions we ran numerous tests throughout the 1990’s. The successful horizontal pilot proved to be a technical success, yielding positive economic results.
EOR – Low Salinity
As technology evolves we are constantly monitoring the optimum method to employ EOR in our offshore assets.
Low salinity water (EOR LSW) highlights the effect salt water has on oil recovery. Replacing sea water injection with low saline water increases the recovery of oil. This is a relatively new concept but one that is nearing maturity in terms of R&D and testing, we are starting to see the global implementation of this extraction technique.
Using water involves much lower capital investment and operating costs, leading to a more favourable financial outcome compared to other EOR methods. In fact, LSW is considered the cheapest EOR method available.
We have conducted a number of studies, and have found that our reservoirs fit the criteria for effective EOR LSW recovery. A pilot is underway prior to field implementation.
Matrix Acid Stimulation
We have long employed matrix acid stimulation to increase the performance of oil, water or gas wells by removing the near-wellbore damage, that is the natural byproduct of drilling and production operations. Every stimulation job is unique and is influenced by certain factors.
Over the years, carbonate acid treatments have been designed to target stimulation of the hydrocarbon zone through the removal of near-wellbore damage and the resulting wormholes. When considering ‘mature high-water-cut’ fields, successful stimulation treatment involves reviewing the good history, reservoir characteristics, and potential production results before selecting the optimum stimulation treatment.
Placement strategy and diversion techniques lie at the heart of any matrix stimulation treatment design. They are the two key considerations when trying to achieve the objective of uniform liquid penetration throughout the entire section or into each natural fracture system. The danger is that full production will be negatively affected if complete coverage is not achieved.
We practice a number of placement and diversion techniques, that include:
MECHANICAL METHODS
CHEMICAL DIVERTER TECHNIQUES
DIVERSION OF FLUIDS
PUMPING STRATEGY
Many of these techniques are not used in isolation. For example in long horizontal sections, our team will utilise a combination of the above methods, like coiled tubing for placement in conjunction with foamed fluids for diversion.
Hydraulic Fracturing
Hydraulic fracture stimulation has been a hotly debated topic for over a decade. Small or isolated cases are often deemed too expensive, risky and complex.
However, over the last few years technological advances, around operational efficiency, has led to a renaissance of sorts. Initially, this has been seen at onshore source rock reservoirs predominantly in North America. It is worth noting that such onshore advances cannot be automatically transferred to offshore extraction due to complex logistics, limited space, and environmental constraints. April 2016 marked a historic moment in our history where we completed the world’s first offshore multi-stage proppant fractured horizontal well, that specifically targeted a tight carbonate source rock reservoir. This was one of the largest and most complex offshore stimulation jobs ever attempted. We achieved this whilst limiting environmental impact utilising a closed loop system transporting flow-back fluids directly to our offshore production facility.
Waterflood
Waterflooding is the most widely used fluid injection process in the oilfield, as it’s a cost-effective and proven technique for increasing oil recovery.
Historical Background
The reservoir was discovered in 1967, followed by development and first production in 1970. Water flooding began in 1974 based on injection wells patterned as radial-oriented spokes and peripherally at the oil-water contact.
Functional Description
Our waterflood facilities are designed to deliver filtered, deoxygenated seawater under sufficient pressure to facilitate secondary oil recovery. The total throughput of our waterflood facilities is running through four parallel trains. Pressurised processed seawater is injected into reservoirs through water injection wells in satellite platforms.
At any time four high-pressure injection water pumps are working. These pumps discharge high-pressure water to a distribution header linking four trunk lines via a subsea pipe network to wellhead platforms.
The process is inter-tie at lift pump discharge, sand filter discharge, Vacuum tower outlet and Primary booster discharge to operate the plants independently in Single Mode or as one plant in Duel Mode.
Drill the well on Simulator Training at Maersk Training facilities, DWC
The company drilling team worked together with MAERSK training technical instructors, on a specially developed programme, as part of the ‘Team T03 well 8-1/2” section drill-the-well-on-simulator training’: The DS-6000 simulator has been set up to mimic the NMOB surface set up, including the add-on MPD equipment allowing early kick detection and application of a surface back pressure) and the actual/planned T03 well parameters. The combined offshore crew (Noble senior drilling crew, Weatherford MPD Operators, Schlumberger Geoservices Mud loggers, drilling engineers and our MOB drilling personnel) have gone through an extensive programme including practical exercises to prepare for all possible eventualities, to apply correct HPHT procedures and to react swiftly to well control situations and test team communication. The 8-1/2” hole section on Team T03 presents several challenges, the well features true wildcat sections, where pore pressure uncertainty exists and potential pressure ramps may be experienced.
4 separate sessions have been successfully delivered in February and March 2017. The sessions garnered an array of positive feedback, adding direct practical exposure and highlighting teamwork, all delivered in a timely fashion, with the drilling of the 8-1/2” section commencing March 2017.
Unconventional Oil
menapetro Formation – an unconventional reservoir
Numerous tests have concluded that the Formation is an example of an unconventional hydrocarbon reservoir. This formation is the source of the majority of offshore oil reserves . The reason for its prodigious oil generation is the rich rock source featuring a high density of organic matter. The Foundation is a wide-ranging formation that varies in ‘true vertical thickness’ between 100 and 400ft, usually found between two water-bearing formations.
We have successfully produced from source rock in several different locations. A number of these tests were performed below the known field ‘oil-water contact’ which resulted in true ‘dry oil’ production, which confirms the production originated directly from the source rock.
True pioneer
This type of production is not without challenges, in order to produce from the ultra-tight rock formations, a large volume of proppant and fluids were pumped, at high pressure, to multiple sections of the horizontal wells and subsequently into the reservoir to create fractures allowing the hydrocarbon fluids to flow. This type of proppant fracturing extraction was pioneered by our team in offshore locations.
Acid Fracturing
Acid fracturing is a good stimulation process. Typically an acid (usually HCl), or a viscous nonreactive fluid (the pad fluid) is injected into a carbonate formation at a pressure sufficient to fracture the formation. As the acid flows along the fracture, it causes a chemical reaction and portions of the fracture face are dissolved.
Acid fracturing can only be applied when the reaction rate between acid and the rock is intense, fast and complete. For example in carbonate reservoirs using HCl, combined with organic acids. This type of treatment is dependent on the fracture length and on the conductivity of the fracture.
We have been employing acid fracturing since the early 1970’s. However, this was restricted to our vertical wells. It wasn’t until the early 2000’s that a number of carbonate rock-based horizontal wells were acid fracced using coil tubing. Fast forward to 2014 and we began multi-stage acid fraccing on four horizontal drains in different fields. The campaign started with the drilling of T-14B well, this became the first offshore multi-stage acid fractured horizontal well.
Gas Lift
Most wells will flow naturally as the natural pressure from the reservoir and the formation gas force the fluid to the surface. Over time as the reserves diminish so too does the energy used to transport the oil to the surface. When this occurs it is necessary to introduce an artificial aid to maintain the flow. Gas Lifts are one such method. As an example in the late 1960’s the reservoir began production, this flowed naturally through until the early 1980’s. At such time the Gas Lift Facility was commissioned to oversee the secondary oil recovery in this field. This is an ongoing process throughout our fields, to put this requirement into perspective 96% of our wells lift oil using gas lifts.
Historical Background
menapetro reservoir was discovered in 1967. After producing naturally for almost 10 years in July 1981, the Gas Lift facility was commissioned as part of the ongoing secondary oil recovery plans. During 1988, the Central Compressor Platforms (CCP) #3 and #4 were commissioned for providing additional gas lift facilities. Currently, 96% of wells are lifted via gas lift.
Gas Processing Facilities
The central complex receives associated gas and lifts gas from producing wells across the various fields. The associated and lift gas is separated from liquid production in the separators. The HP separator outlet gas is sent to the lift gas compression facilities and distributed to producing wells. The lift gas system is essentially a closed-loop.
The total gas lift compression capacity is ~ 1000 MMCFD, distributed by platform and trains. Lift gas compression facilities include two trains of 2-stage turbine-driven centrifugal units on each CCP, except for CCP-3 which has an additional compression train for the EOR pilot. Each compressor train is complete with suction and interstage gas scrubbers and interstage/discharge gas coolers. The compressors take suction gas from the HP separators at 110 psig and discharge at 1600 psig. The EOR pilot compressor is fed from this discharge and is capable of further compressing the gas to 5200 psi.