The formation of hydrates in natural gas wells and pipelines presents a serious concern to oil and gas producers. Hydrate deposits form solid plugs, reducing production and ultimately shutting in the well. Costly, labor-intensive intervention is required to remove the hydrate blockages and return the well to production. Traditional usage of methanol to inhibit hydrate formation has been ineffective.

Improved solutions using low dosage hydrate inhibitors (LDHI) in conjunction with methanol

Graph 1. The shaded area represents the operating conditions where hydrates are unstable and predicted not to form. The area left of the curve is where hydrates are stable. A system operating in this region is at risk for hydrate formation. The red line is referred to as the “Hydrate Equilibrium Curve” for the system. (All graphics courtesy of Baker Petrolite)
have been developed by Baker Petrolite (BPC). The solution, referred to as “Supercharged Methanol,” reduces chemical requirements, resulting in:
• Reduced hydrate formation;
• Reduced costs;
• Reduced exposure of personnel to hazardous situations; and
• Increased production efficiency.
These benefits reduce lifting costs and improve operating profits.

Production issues
Gas hydrates in natural gas systems are comprised of water and low-molecular-weight gas molecules. For each production system, hydrate equilibrium curves can be prepared which
Graph 2. This graph shows an example of a well operating at 1,500 psi and 50ºF (10ºC), conditions which are inside the hydrate formation zone. The subcooling is approximately 18ºF (7.7ºC).
take into account gas and water compositions. These curves show the conditions of temperatures and pressures at which hydrates are thermodynamically stable and likely to occur.

A wide variety of conditions can exist in a given oil and gas system. Some of these conditions move a system or well from the hydrate free zone into the hydrate formation zone. They include:
• High operating pressures;
• Sub-surface cool zones (permafrost or aquifers); and
• Seasonal surface issues (winter or rainy season).
There are several viable ways to remove a well or system from the hydrate formation zone:
• Reduce operating pressures;
• Increase operating temperatures; and
• Remove water.

Another approach is to use chemicals which act as hydrate inhibitors, shifting the hydrate equilibrium curve to the left, moving the system to the hydrate-free zone.

The most commonly used chemical for this purpose is methanol, a thermodynamic hydrate inhibitor (TDI). If used in correct quantities, methanol prevents hydrates from forming. Methanol requirements may be >50% by weight of the produced water. Hydrate-prediction software can calculate amounts of methanol required, taking into account production, operating conditions, and chemical compositions of water and gas.

Other chemicals that work at lower rates than TDI, LDHI, are available. LDHI are classified as
Graph 3. Methanol injection shows a substantial change in subcooling.
either Kinetic Hydrate Inhibitors (KHI) or Anti-Agglomerants (AA). KHI products affect the time it takes hydrates to form. They delay hydrate formation, allowing production to flow out of the hydrate-formation zone. AA products behave differently, allowing hydrate crystals to form but limiting their size and keeping them oil-wet. This allows them to pass through the system without forming deposits. AA products inhibit systems for extended time periods, making them especially suited for deepwater projects.

Problems with methanol
While methanol is an effective TDI, there are issues associated with it. Foremost are environmental and regulatory concerns due to the high amounts required to control hydrates.

Wells operating in the hydrate formation zone may require high concentrations of methanol based on water production. For such a well producing 50 b/d of water, 700 gallons of methanol per day are needed. This requires:
• Extremely large bulk tanks on site;
• Hazardous material permits; and
• Monitoring hazardous air pollutants (HAP) and volatile organic compound (VOC) emissions.

Safety/environmental hazards are also present when transporting and handling the methanol.

High financial risk is incurred due to the volatility of the methanol market. Since methanol price is tied to natural gas price, as gas prices increase, methanol prices increase. Increased global demand for methanol causes steep price increases. In a single year, the methanol price may double, making it difficult to plan hydrate- treatment costs. In situations like these, the tendency is to reduce methanol usage to stay within budget.

Inadequate methanol usage leads to problems as identified by M.H. Yousif (SPE, Westport Technology Center Int., Effect of Under-Inhibition With Methanol and Ethylene Glycol on the Hydrate-Control Process, SPE Production & Facilities, August 1998). Studies show that hydrate molecules and line blockages form more readily in systems using insufficient quantities of methanol. By reducing methanol amounts, producers may be exacerbating hydrate formation, creating additional production problems.

Other methanol related problems:
• Methanol contributes to corrosion by absorbing and carrying oxygen;
• Methanol is a bacterial food source;
• it causes water quality and separation problems;
• It adversely affects foamers/surfactants used to deliquify wells; and
• Refinery issues can result in downgrading of oils and condensates.
Problems with injection systems
Perhaps the weakest link in controlling hydrates with chemicals is the injection system itself. Regardless of type of chemical inhibitor used, rules apply:
• Inhibitors won’t work unless injected into the system;
• Inhibitors need to be injected at the proper effective dosage; injecting too much adds additional cost, and not injecting enough may exacerbate problems;
• Inhibitor supply tanks must be refilled (or tank empties and hydrate plugging occurs).

Several issues have been identified which impair a chemical injection program: pumps get
Case 1. Supercharged methanol offers a substantial gain in well performance.
air-locked and don’t inject inhibitor, rates are set higher than expected, the inventory is used up prior to replenishing the supply, injection lines break, power failures occur, lightning strikes, etc. Maintaining and inspecting injection systems is labor-intensive. In remote locations containing thousands of gas wells, it is impossible to insure system reliability.

As a consequence, injection systems aren’t adequately monitored, resulting in:
• Not injecting correct inhibitor amounts;
• Failing to change injection rates when conditions change;
• Pump failures;
• Not inspecting injection systems due to weather;
• Failing to replenish chemical inventories;
• Forgetting to turn pumps on;
• Air-locked pumps; and
• Chemical losses due to tank ruptures or line leaks.
For producers, it adds up to losses in revenue, higher operating expenses, environmental compliance issues and reduced profits.

Hydrate remediation
A variety of methods are used to remediate hydrate problems. When hydrates form, operators must increase temperatures, reduce pressures or chemically melt plugs.
Case 2: Revenues increased more than $500 a day when the proper methanol treatment was applied.
Remediation efforts expose field workers to unforeseen hazards, as the exact location and extent of the problem is generally unknown. Injuries and fatalities have occurred owing to:
• High pressure buildups on one side of the plug, launching the plug when pressure is released on the other side;
• Highly compressed hydrate plugs causing lines to rupture when heat is applied to the outside of the pipe (182 cf compressed gas equals 1 cf hydrate).
• Released downhole hydrate plugs shooting out through the well head.
• Released hydrate plugs in pipelines traveling at extreme speeds and shooting out of bends in the pipeline.

Additionally, labor costs and lost production due to venting the wells to the atmosphere to depressurize lines is extremely costly.

Improved solutions
Working with industry consortia, Baker Petrolite sought to find the most cost-effective solutions for hydrate control.

Oil and gas production systems are complex with many variables. To study the problems and develop solutions, BPC uses state-of-the-art laboratory testing methods which enable researchers to evaluate performance under conditions matching those found in production systems. Specialized high pressure, thermally controlled test vessels are used to create hydrates in the laboratory. Software models are employed to predict theoretical treatment rates for TDIs.

Baker Hughes Production Quest has developed solutions to improve hydrate inhibitor injection systems. These include:
• Pump controllers, insuring injection of exact amounts of hydrate inhibitor; and
• Tank level sensors monitoring chemical inventory 24/7.
The controllers and sensors provide automatic, real-time injection system coverage. Alarms are triggered when processes fail, notifying operators immediately so the problems can be fixed. These chemical automation systems
have helped producers reduce failures, increased worker safety and improved operating profitability.

Results from field trials
The results from two field trials performed are presented below. LDHIs were combined with methanol to improve performance of the hydrate-control program. This combination product was injected in conjunction with the chemical automation system for improved control of the injection system. Overall results indicate that hydrate formations were reduced and system failures declined. Program benefits include:
• Improved logistics
- Reduced chemical injection;
- Smaller tankage requirements with increased time between deliveries;
- Reduced costs; and
- Better cost management.
• Chemical injection automatically adjusted to conditions
- Instantaneous notification of problems; and
- Changes in system conditions triggering automatic notification.
• Improved HSE performance
- Reduced risk due to remediation techniques employed at the field level;
- Reduced road time to/from site; and
- Reduced environmental impact (wildlife disturbance).
• Improved profitability
- Reduced total operational cost;
- Increased production.

Case #1
A gas producer in southwest Wyoming experienced severe hydrate problems in a gas well. The hydrate plugs required high levels of maintenance, and the well produced below expectations. Continuous injection of methanol failed to control the problem. The remote location of the well required extensive labor and engineering support to keep the well running.

The remoteness of Wyoming gas fields makes manual monitoring injection systems difficult, if not impossible, to do on a timely basis.

Consequently, the producer experienced high operating and remediation costs, production losses, and lower than expected production. The hydrate remediation also increased safety risks and environmental concerns.

The service company and producer assessed the problem to determine subcooling in the well. Hydrate-modeling simulations were run to determine amounts methanol needed. Lab studies selected HI-M-PACT 5557 KHI as the ideal product to use in conjunction with the methanol and foamer. The methanol was supercharged with the addition of HI-M-PACT 5557 KHI and applied continuously down the back side of the well, resulting in a production increase of more than 350 Mcfd.

As a direct result of the LDHI program, production stabilized, treatment efficiency increased and safety risks were reduced significantly. The customer realized an increase in revenues of almost US $12,000 per month and a more than 4,000% return on investment. Also realized was a decrease in workover costs, manpower requirements and engineering time, and expenses were minimized because the existing chemical system (i.e., storage tank, pump, etc.) were utilized. The customer maintains lower volume of chemical on site, reducing Superfund Amendments & Reauthorization Act reporting and making inventory easier to maintain. Reduced methanol usage lowered hazardous air pollutants at evaporation ponds.

Case #2
Another Wyoming gas producer was plagued with hydrate problems in gas wells. Although costly remediation efforts were repeatedly performed to remove hydrate plugs, the well continued to produce below projections. Continuous injection of methanol was applied, but it failed to bring the well’s performance to an acceptable level.

As a result, the customer experienced high maintenance costs and production losses, and financial performance was below plan. Safety concerns during the remediation of the hydrate plugs and the excessive engineering time dealing with hydration remediation were also issues.

The service company and the producer assessed the problem. Hydrate-model simulations and lab tests were run to determine the optimal chemical amounts. Based on the tests, HI-M-PACT 5458 KHI was selected as the most favorable KHI to use with the methanol. The results were a supercharged methanol/KHI product that proved highly successful for the customer.

Utilizing the treatment program, gas production increased more than 65%, and revenues increased more than $500 a day. The return on investment was almost 4,800%, and the payback period was about 29 minutes.