Day-to-day, oil-and-gas production often comes from wells in harsh conditions* that are situated in some of the world's most remote locales. While oil's rising price makes big media headlines, the daily work in the field is to maintain steady production. The opportunity to increase revenues and meet growing market demand offers added incentive to identify technologies to optimize production tec...
AT A GLANCE
Unstable well
Intelligent control valve
Remote control, monitoring
Quick ROI
Day-to-day, oil-and-gas production often comes from wells in harsh conditions* that are situated in some of the world’s most remote locales. While oil’s rising price makes big media headlines, the daily work in the field is to maintain steady production. The opportunity to increase revenues and meet growing market demand offers added incentive to identify technologies to optimize production techniques.
This was the motivation that brought Alaska-based Flowserve Flow Control distributor Joe Gross, president of Alpine Valve & Control Systems, to collaborate with Unocal Alaska. Alpin, Unocal, and Flowserve engineers designed, implemented, and resolved Unocal’s well production-problems. Flowserve’s StarPac intelligent control-valve helped stabilize well performance and improve production on the company’s Monopod offshore-platform in the Upper Cook Inlet in south-central Alaska. Besides increasing revenues, a cost advantage was gained over conventional valve technology.
Upsets impact output
Years of experience with offshore oil wells have shown, “Oil wells are sensitive creatures,” says Gross. “They are subject to upset at the slightest provocation.”
Upset oil wells led Gross to meet with Justus Hinks, Unocal production engineer on the Monopod platform. Installed in 1967, Monopod was one of Cook Inlet’s first oil-and-gas platforms. The well had posed a series of problems, including instability, restricted production, and high, gas-lift usage rates. Gross and Hinks had to determine whether StarPac could control the well’s gas-lift flow rate, thereby stabilizing the well, increasing fluid production, and decreasing gas volumes needed for operation.
Beyond conventional gas-lift
Oil from Monopod’s wells does not flow to the surface naturally, requiring assistance from the platform. Although there are many different technologies available, Monopod employs conventional gas-lift. This technique pushes highly compressed natural gas thousands of feet to the well bottom. Gas bubbles up through the fluid column, making the liquid lighter—allowing the reservoir pressure to deliver more fluid to the surface. At the surface, components of the produced fluid—oil, water, and natural gas—are separated. Then natural gas is recompressed and reused in the gas lift cycle; and, traditionally, lift gas flow is not actively controlled.
However, Gross and Hinks suspected the unsteady well could be stabilized by using a control valve to precisely regulate its gas flow. “I was aware that this well was not behaving correctly,” says Hinks. “Joe had heard through Flowserve that StarPacs were being used successfully elsewhere to actively control gas lift flow rates and enhance well performance. Most gas lift applications use manual choke valves to control lift gas to the well,” adds Hinks. “This means that most operators can only estimate the flow rates delivered to the well bottom. They don’t have the ability to accurately control it.”
“Many people believe that manual valves control flow, but that’s not really true,” says Gross. “In fact, by setting a manual valve to a specific position, the desired rate of flow is only maintained when the differential pressure—disparity of the upstream and downstream pressure—is constant. This is rarely the case. While gas-lift header pressure is relatively constant, pressures within the well vary widely, resulting in large swings in lift-gas flow rate. Changes in the gas rate at the surface cause dynamic changes in the well starting at the bottom and working up to the surface sometime later,” notes Gross.
“Since the typical oil reservoir can be over a mile below the wellhead, many subsequent, and sequential, upsets can be induced before the previous ones reach the surface. So the well is constantly unstable, resulting in suboptimal production. The goal with gas lift is to maximize total fluid production; that’s what optimizes revenue. Key to reaching this goal is keeping wells stable at their ideal rates by making as few changes as possible at the surface. This is accomplished by first identifying the optimal gas rate and then holding it by maintaining precise, automatic control.”
Gross and Hinks thought that the StarPac control-valve’s embedded intelligence could resolve the problem. The valve features a:
Variety of process sensors;
Microprocessor-based controller; and
High-performance digital positioner.
Since all the elements are integrated within the valve it’s effectively a “complete PID control-loop between the flanges.”
The valve’s functional capabilities include:
Flow measurement and control;
Back pressure control;
Pressure regulation;
Differential pressure control; and
Temperature control.
Choosing an erratic performer
Believing that the StarPac could improve production at a lower installed cost than a conventional automated control-loop, Gross and Hinks set out to test the idea. After evaluating historical production data, they chose one of the Monopod’s 16 wells for the trial. Drilled in 2001, the well performed inconsistently at the outset. Because the well was originally designed for higher production rates than presently realized, excessive lift gas was required.
Additionally, the well was experiencing “multi-phase slugging,” which was affecting the entire platform’s process stability. The only previously identified fix—modifying the well internals—had an unacceptable, multimillion-dollar price tag with expensive downtime.
Greg Geller, Unocal platform’s lead-operator, explained, “The unstable well was taking too much gas to lift. The platform can only supply 20-million standard-cubic-feet per day of compressed gas; this was insufficient to bring all of the wells to full capacity.”
“Stable wells are more productive,” notes Dave Cole, Unocal Alaska oil team-leader. “One well on the platform can make all the (other) wells unstable.”
Risk-free trial
Gross and Hinks’ research convinced them that the trial valve would pose little financial risk and had potential to provide a rapid return on investment. “When I presented the StarPac solution to Unocal, I said that controlling the gas flow on the surface would improve the overall performance of the well, increasing revenue,” says Gross. “I predicted that it would pay for itself in under a month.”
Unocal was promised five benefits in a risk-free trial:
The well would be stabilized;
A 10% increase in total fluid production;
Lift-gas required for the well would decrease 10%;
The valve system would be a very useful analytical tool; and
Control would be easier for the well operators.
The cost of installing StarPac fit within the platform’s budget. After Unocal management agreed, Gross and Hinks began collecting the well’s baseline-performance metrics. After a service-and-maintenance check, the valve was installed.
Initially, StarPac was operated in manual mode to mimic performance of the old, manual choke-valve. Once certain that the valve was offering performance similar to the choke valve, flow rates were altered, and the valve was setup to automatically maintain those rates. Again, performance data was collected and analyzed against the baseline data to determine if the benefits had been achieved.
On target
Performance data compared to baseline data showed most targets were met, says Hinks. “Of the five goals, four were achieved.” While lift-gas usage has remained essentially unchanged—due to the existing well design—the well is now much more stable and is producing more oil. StarPac also has provided a remote status and control tool for well operators and an analytical tool for the production engineers.
“Because we have data in real time, any well problems are much more obvious,” says Geller. “It has allowed us to spot and control potential upsets that we otherwise wouldn’t have found so quickly,” allowing analysis of well status, performance, throughput, and operational efficiency. Based on valve data, mechanical adjustments were made to the well to further improve its performance, explains Geller.
“We bought a valve and got a flow control solution because of the extra features that are integrated into it,” says Hinks, who likes the control and analytic features.
Quick ROI, productivity
Return on investment for the installation was one to two months. According to Cole, overall costs, including installation labor, were under $40,000. Hinks believes the changes to the well, which was producing 340 barrels/day of crude and is now producing 382 barrels, will boost well profitability by 12%.
Other benefits include remote diagnostics-and-control capability.
“Our automation engineer built several screens that allow me to access the system remotely,” says Hinks. “Now, with my computer in the Anchorage office, I can find out how the well is doing.” It saves Unocal about $1,500 for each avoided trip to the platform—comprising Hicks’ expenses for: air travel, a rental car, and helicopter.
Gross says they are evaluating using the valve on additional wells on this and other platforms.
“With oil prices at record highs and a potential fluid-production increase of up to 15% per well, the demonstrated payout of a StarPac application can be measured in weeks,” says Gross.
