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Saudi Aramco Moving Forward on Unconventionals

Trent Jacobs, JPT Senior Technology Writer

With the world’s fifth-largest estimated shale gas reserves, there is great potential for Saudi Arabia to replicate North America’s unconventional growth. Saudi Aramco’s unconventional program became operational in 2013 and the company has been working with major service companies, including Halliburton and Schlumberger, to develop the reserves.

The primary driver is the country’s pressing need to find new supplies of gas to replace the domestically produced crude oil used to generate most of its electric needs, demand that can reach as high as 900,000 B/D in summer. Another major aim is to use unconventional gas to bolster the country’s growing petrochemical industry.

Ali Almomen, an unconventional gas production engineer at Saudi Aramco, said the company has completed the exploration and appraisal phases of its derisking strategy and is in the middle of various pilot stages. He provided an overview of the company’s progress at the recent SPE Annual Technical Conference and Exhibition in Houston. “We are trying to fine-tune the technology, trying to reduce the cost, and improve the [estimated ultimate recoveries] further,” he said.

To accelerate the effort, the national oil company has so far committed at least USD 10 billion to its unconventional exploration program and is actively recruiting experienced unconventional experts from North America to join its ranks.

The company’s unconventional ambitions are focused on three different areas in Saudi Arabia. The first is located in the northern part of the country. The target formation is called the Qusaibia Hot Shale and is found at a depth between 6,000 ft to 8,000 ft. The shale is considered to be relatively shallow and is the source rock for conventional gas fields in the area. The gas produced from this area will support a major mining project still under construction and a new power plant.

The other two plays are in the eastern province and located along the periphery of the Ghawar oil field, the largest conventional oil field in the world. These two areas will benefit from their proximity to existing infrastructure and the large amount of geological data already collected from the development of Ghawar.

The play located to the south of Ghawar is a deep tight sandstone formation where five appraisal gas wells have been drilled so far. Sitting just east of Ghawar is the third play where Saudi Aramco is targeting a tight carbonate formation called the Tuwaiq Mountain—the source rock for the giant oil field. The company believes this field is comparable in many respects to the Eagle Ford Shale in Texas. “Sometimes, it is better than the Eagle Ford in terms of the permeability and porosity,” Almomen said.

The Tuwaiq Mountain formation is split into two tiers. The upper tier has nearly double the total organic content of the Eagle Ford while the lower tier is about the same. A pilot well drilled in the Tuqaiq Mountain formation had an average 30-day initial production rate of 3 MMscf/D of gas and 1,800 B/D of oil.

In addition to core samples and openhole logs, sonic logging tools and ­diagnostic fracture injection testing are being used to make key determinations about each formation’s permeability, pore pressure, and in-situ stress state. Using this information, completion engineers are placing as many as 16 fracture stages along the laterals. They are placing the stages only in the areas that appear to have the best production characteristics and are avoiding areas with poor reservoir quality. Based on production logs, Almomen said this strategy has resulted in 95% of the perforation clusters contributing to production in some of the best cases.

The company’s plans include using microseismic surveys and chemical tracers to better characterize fracture networks and to determine how cluster stages are contributing to production. The company is also investigating technologies to overcome the challenges involved with hydraulic fracturing in the middle of the Arabian Desert. “We are experimenting with local sand and we’re doing some research on water management, testing, and trying to create a decent frac fluid using sewage water, seawater, and other fluids,” said Almomen.

He added that once the company reaches the development phase, it will continue work on driving down costs and adopt factory-mode drilling techniques pioneered by shale producers in the US and Canada.


Enhancing Sand Strength for Fracturing Applications

Pam Boschee, Senior Manager, Magazines

Sustaining the fast economic growth in Saudi Arabia requires a ramp up of the gas supply. A strategic objective of Saudi Aramco is exploring and developing deep and unconventional gas reservoirs, many of which are considered extremely tight. These formations need hydraulic fracturing to allow the hydrocarbons to be efficiently produced. Unlike in North America, the infrastructure to commoditize the drilling and production processes is immature in Saudi Arabia. Therefore, many cost-reduction measures have to be exhausted, especially on materials. Proppant is the main material used in fracturing and, therefore, reducing its cost affects greatly the economics of any fracturing operation.

Although the country has abundant natural sand resources, the strength of the sand is insufficient to withstand closure stress in most of the gas reservoirs. New technology can enhance the local sand strength to make it deployable in deep formations with closure stress greater than 10,000 psi.

The company is developing new technologies to further maximize the economics of hydrocarbon resources and to promote growth of the domestic economic potential by becoming a potential exporter of upstream oil and gas technologies and products. With increasing hydraulic fracturing activities in the country, Saudi Aramco is carrying out multiple hydraulic fracturing research and development programs in its upstream Advanced Research Center (EXPEC ARC). One of the most important initiatives is to enable fracturing with Saudi local sand.

A short-term solution is to integrate the local sand in a pillar fracturing technique. The pillar fracturing creates aggregated and competent sand piles. Among the sand piles are open channels to allow hydrocarbons to flow freely into the wellbore. Pillar fracturing design provides the benefit of rapid fracture cleanup and, therefore, maximizes initial production rates as well as long-term sustained productivity. Various chemical and physical means are being investigated to stabilize the aggregated sand piles so that the fracture propping pattern is sustained over the life span of a well. The goal is to properly use this low-cost resource with sound engineering practices to achieve a cost-effective fracturing technique.

The mid-term solution is to develop new materials to coat the sand grains so that the actual strength of each individual sand grain is significantly increased. This will broaden the range of the applicability of the Saudi local sand to fracturing treatment designs by allowing the use of the local sand in conventional proppant packing pattern instead of being limited to the pillar fracturing techniques.

EXPEC ARC’s unconventional re-sources department and a technology collaborator have worked together in defining R&D protocol and performing lab tests on the pillar fracturing technology with Saudi local sand. The lab testing showed that pillars created by Saudi sand and a chemical agent can withstand closure stress greater than 12,000 psi. Parallel testing using commercial high-strength proppants indicated comparable performance. The effluent contained nearly no fines nor crushed particles, and the conductivity remained near infinite, indicating the flow channels are propped open effectively even at very high closure stress. Table 1 illustrates the performance of the material.

Saudi Aramco is planning field trials to begin in early 2016. The cost of the proppant material in fracturing is expected to be reduced by at least 50% using this technology combined with Saudi local sand. The next phase of development is to find low-cost chemical means to enhance the sand grain strength.


Competing Companies Building Robots to Place Receivers

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

Autonomous Robotics’ first offering is built around a rounded yellow device that looks like a little flying saucer. It is more of a seismic saucer because it is designed by the UK startup to “fly” from a drop-off point in the water to a designated spot on the seabed, where it will record seismic data until it is ordered to return.

The company was one of two firms displaying flying nodes under development at the recent Society of Exploration Geophysicists (SEG) annual meeting in New Orleans. The other was Seabed Geosolutions, which has been working with Saudi Aramco since 2012 to develop a flying node called Spice Rack.

At the SEG meeting, Seabed presented a new version of its self-propelled node at its exhibit booth. An animated video showed its flying nodes being released from a basket lowered into the water by a remotely operated vehicle (ROV). A company representative said it was working with Saudi Aramco on an update for the project.

While most offshore seismic service sectors are in a deep slump, node demand is relatively stable because the technology is most often used for creating high-quality surveys in producing fields, said John Moses, a regional sales director for Seabed.

While ropes can be used to place nodes in water depths to 1000 m, ROVs are needed for accurate placement at greater depths, he said. ROVs are precise, which is required for repeated surveys over time showing field changes. But the cost of using them limits the size and density of the arrays placed, reducing the kinds of work that can be done and the quality of the output.

Developers of self-propelled nodes are out to lower the placement cost in deep water. Autonomous Robotics believes its self-propelled nodes are 10 times faster than ROV-placed nodes, said Dave Grant, chief executive officer of Autonomous Robotics, with up to 1,200 nodes placed a day compared with a high estimate of 100 per day using an ROV.

“For ROV-deployed nodes, as you increase the density, the cost of a survey escalates because of the limited pace of deployment. The cost goes up much less rapidly with flying nodes,” said Arran Holloway, engineering manager for Autonomous Robotics.

The precision of the placement is expected to be as good as an ROV because the navigation system used for the autonomous flying nodes is the ultra-short baseline (USBL) method used for ROVs, with modifications expanding the number of devices it can control.

The nodes from Autonomous Robotics will combine an internal navigation system with course corrections from two moving vessels, the main node vessel and a smaller autonomous surface vessel that stays in contact with the nodes as the main vessel moves out of range.

Autonomous Robotics will use heave-compensated launch and recovery systems to lower cages full of its saucers to below the turbulence of the surf zone. At their maximum depth of 3000 m, the nodes are expected to be able to remain in place 60 days, and likely longer at shallower depths where less power is required in transit, Holloway said.

Autonomous Robotics is currently in the process of building a prototype of its flying node, Grant said. That is the centerpiece of an automated operation. The company’s modular system that can be installed on an offshore work vessel, such as an ROV handler, includes an automated handling system that will move the nodes to and from storage racks to stations where they are cleaned, charged and the data downloaded, and also to the cages used to lower them into the water.

The company’s vision of robotic offshore operations is generally based on building blocks that are now in use. “A lot of the technology is used for slightly different purposes offshore,” Holloway said. That includes the material covering the outside of the saucer, the small thrusters, the navigation system, and software used for placement.

Each of the saucers has three thrusters, two aimed horizontally on the sides propelling it forward, and a third vertical one near one end helps peel it off the bottom when it is time to return and to adjust its glide angle.


Flow Sensor Technology Seeks to Replace the Coriolis Meter

Trent Jacobs, JPT Senior Technology Writer

Australian technology developer MezurX is touting its newly introduced flow, density, and mud monitoring system as a significantly better alternative to the widely used Coriolis meter. Using an advanced set of sensors, the X-Omega provides real-time information that can be used on rigs for early kick detection and managed pressure drilling (MPD).

Bruce Henderson, president and CEO of MezurX, claims the technology involves “a completely different way of measuring density and flow” while offering more reliability and a smaller footprint than Coriolis-based systems.

And despite the current price environment, Henderson said several service companies and offshore operators are showing interest in the X-Omega system and work has already been awarded. “It’s an interesting time for us,” he said. “I think that during a downturn in the industry, new technology is always attractive to keep costs down and make things more efficient.”

MezurX is listed on Chevron’s website as one of several firms the oil and gas major is funding through its venture capital division to promote the development of emerging upstream technologies.

The X-Omega was created by integrating the company’s proven flowmeter and pressure sensor technologies, along with software to interpret the data.

As drilling mud enters the system through a return flowline, the fluids are first measured by a density module that contains a pressure sensor, then a wedge-meter analyzes the flow velocity, and a second density module on the back end takes another pressure measurement. This simultaneous measurement of two parameters delivers real-time flow data required for MPD operations, as well as early kick detection, and reduces nonproductive time.

Coriolis meters used on offshore rigs typically require height clearance of about 14 ft vs. the 4 ft needed to install the X-Omega. The modularity aspect of the X-Omega system means it can be configured horizontally, vertically, or at right angles to address rig design. One benefit of this nearly-in-line capability is that the pressure drop in an X-Omega meter is about 35% less than a Coriolis meter of equivalent capacity because the internal passageways of the X-Omega have a larger diameter and have less obstruction, Henderson said.

The new system has yet to be used in the field, but Henderson said the com­pany’s confidence relies on the established track record of its individual components, which have been used on rigs for various applications in identical drilling environments. The flow sensor has been used on offshore rigs to measure both oil- and water-based drilling muds. The pressure sensor technology has also been used offshore for early kick detection and undergone extensive testing at the company’s flow loop simulator in Brisbane, Australia.