Taking a next stepExxonMobil applies for AOGCC gas injection order for Point Thomson field Alan Bailey Petroleum News
In another move towards bringing the huge Point Thomson gas condensate field on the North Slope into production, ExxonMobil, the field operator, has applied to the Alaska Oil and Gas Conservation Commission for permission to inject gas into the field reservoir. In a July 7 AOGCC public hearing company officials told the commissioners that the production of condensate from the field will require the recycling of 194 million cubic feet per day of natural gas from the field, with that gas being injected at high pressure into the reservoir through two injection wells.
The Point Thomson field reservoir contains a mixture of natural gas and condensate, a very light form of oil, at a very high pressure. Because reservoir pressure must be maintained, to prevent the condensate dropping out of solution inside the reservoir, gas at high pressure will need to be continuously cycled through the reservoir using an appropriate configuration of wells. Condensate will be extracted from the gas after the gas reaches the surface through a production well, before the gas is sent back underground through injection wells. The condensate will be transported by pipeline into the North Slope oil pipeline system, where it will be mixed with crude oil from other fields for delivery into the trans-Alaska pipeline, for shipment to market.
ExxonMobil expects initial production of 10,000 barrels per day of condensate.
Two pads, three wells At field startup, which ExxonMobil anticipates happening in early 2016, two gravel pads will be in use, a central pad and a west pad. ExxonMobil reservoir engineer George Eleftheriou told the AOGCC commissioners that a single production well will be located on the west pad, while two gas injection wells will be located on the central pad. The central pad will also house field processing facilities and a well for disposing of water produced from the field reservoir along with gas and condensate, Eleftheriou said.
ExxonMobil has previously said that it plans to drill the production well, the PTU-17 well, starting in the fourth quarter of this year. The company drilled the two injection wells, the PTU-15 and PTU-16 wells, in 2009 and 2010, Eleftheriou said. The original development plan envisaged a single injection well and a single production well but, after ExxonMobil discovered that the field holds some corrosive hydrogen sulphide gas, the company had to install protective liners into the two wells that it had already drilled. Those liners reduced the well tubing size, thus requiring the drilling of a separate production well capable of handling the planned 10,000 barrels per day of production, Eleftheriou explained.
ExxonMobil is in the process of completing the PTU-15 and PTU-16 wells so that the wells can operate as injectors. Drilling Engineering Supervisor Alex Podust said that the completions of all of the wells are designed to prevent reservoir sand entering the well bores. Each well completion involves the installation of a perforated casing with mechanical screens, with small-scale, sand filled fractures extending from the wells into the surrounding reservoir rock.
Eleftheriou said that ExxonMobil anticipates initial gas production of about 200 million cubic feet per day. That is a slightly larger rate than the rate of gas injection, given that some of the produced gas will be required to fuel the field’s production facilities. However, the gradual loss of gas from the field will not have much impact on condensate production, Eleftheriou said. Gas will be injected into the reservoir at a pressure of about 10,000 pounds per square inch.
Field reservoir Since the Point Thomson reservoir extends offshore, under the Beaufort Sea, the wells require directional drilling from the onshore pads, with the wells’ bottom-hole locations being widely spaced in the reservoir. ExxonMobil Senior Geosciences Advisor Susan Dougherty told the commissioners that the reservoir is in the Thomson Sand, a rock unit that is Lower Cretaceous in age and that lies on top of Pre-Mississippian basement rocks. Shales of what is referred to as the Hue/HRZ and of the Canning formation seal the hydrocarbons into the reservoir sands. The gas layer in the field is about 500 feet thick, Dougherty said.
ExxonMobil had based its reservoir modeling on data from 16 wells that had penetrated the Thomson Sand. But results from the PTU-15 and PTU-16 wells have caused the company to rework the model, with those wells demonstrating that the quality of the reservoir is better than previously thought, Dougherty said. In particular, the PTU-15 well, drilled in 2009, had penetrated 130 feet of what ExxonMobil calls the “open framework conglomerate,” a rock with outstanding reservoir quality, given its exceptionally high porosity and permeability. Porosity expresses a rock’s capacity to store fluids, while permeability determines the extent to which fluids can flow through the rock.
Dougherty said that the two recently drilled wells had also encountered another type of conglomerate and a clean sand, both of which also exhibited very good reservoir properties.
Reservoir continuity Moreover, in 2014 ExxonMobil reprocessed the 3-D seismic data for the field and the company has subsequently revised its model for how the reservoir sands were laid down, and how the sand is structured, Dougherty said. The company thinks that the sand was deposited from an ancient river delta in a shallow marine setting. However, while the company previously thought that sediment had been shed in all directions, the revised model involves consistent deposition towards the southwest, leading to broad bands of consistent styles of deposition. That has resulted in increasing confidence that the reservoir is not split into separate compartments, Dougherty said. And, while the seismic data have revealed the presence of faults cutting the reservoir, those faults do not appear to have compartmentalized the reservoir rock, she said.
The continuity of the hydrocarbon reservoir is important for condensate production at Point Thomson, because of the need for pressure communication between the gas injector wells and the production well.
Recycling versus blowdown Over the years prior to ExxonMobil’s development decision, a debate took place over the relative merits of producing condensate from Point Thomson or just producing gas from the field, with the “blowdown” of gas being technically much simpler that the gas recycling production of condensate. The state of Alaska has been anxious to ensure that as much condensate as possible is produced from the field, given that condensate has a higher commercial value than gas. And, in the absence of a North Slope gas export pipeline, there is currently no way of delivering Point Thomson gas to market. The field is thought to hold about 8 trillion cubic feet of gas.
Commission Chair Cathy Foerster asked if ExxonMobil’s new three-well production scheme is as good as the original two-well plan in terms of supporting the gas cycling approach to condensate production. Eleftheriou responded that the gas cycling efficiency should be fairly good but is somewhat dependent on the characteristics of the reservoir rocks. The biggest risk to the gas cycling process is an early breakthrough of gas from an injector well to the production well, Eleftheriou said. A breakthrough of gas through the reservoir direct to the production well would presumably undermine the ability of the injected gas to maintain the reservoir pressure.
Eleftheriou, referencing the upcoming drilling of the production well from the west pad, commented that this new well will provide new information about subsurface rocks in the western part of the field.
“We want to make sure that we can maintain deliverability from that well. We hope to see good reservoir quality,” Eleftheriou said.
Foerster commented that the performance of initial production at Point Thomson will determine how the field continues to be developed.
“So it’s critically important to this agency that you’ve done your best job of trying to ensure that you’ve given cycling every chance to succeed,” she said.
Foerster also asked about the feasibility of oil production from a thin rim of thick, heavy oil below the gas in the field. Eleftheriou said that, given the high viscosity of the oil and its juxtaposition with oil and water, modeling had indicated that production of the oil would be very challenging, with expensive wells and low oil recovery rates.
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