GAS FIELD TECHNOLOGY

Based on a workshop sponsored by PTTC's West Coast Region in Sacramento, California on April 28, 2005.

BOTTOM LINE

California producers operate over 5,000 natural gas wells, producing a total of 350 BCF/year. Still, California must import 85% of the natural gas consumed in the state. This workshop highlights some of innovative technologies helping the economics of operating gas wells in California and an update of the regulatory issues and impediments to gas field operations, with a projection of the opportunities and challenges ahead.

PROBLEM ADDRESSED

California natural gas field operators face a number of technical and regulatory challenges in drilling and producing natural gas. The technical problems include wells loading up with fluids, a produced stream that requires processing to meet pipeline standards and corrosion damage to older wellbore casing. Legal and regulatory problems include siting and permitting requirements for new wells, minimum production required by the utilities, gas quality specifications, and access to markets.

KEY WORDS:

Corrosion control, Gas processing, Infrastructure, Liquid loading, Natural gas supply and demand, Storage well

SPEAKERS:

Introduction
Rock Zierman, California Independent Petroleum Association (CIPA)

Overview of Technologies for Dewatering Gas Wells
James Lea, Texas Tech University

A Review of Gas Processing and a Case Study
John Crews, Cannon Associates

Corrosion Control of Well Casings
Saibal Mitra, CORRPRO

An Overview of California Gas Storage Well Completions
Mike Gleason, Baker Oil Tools

Natural Gas Situation in the Western US and Canada
Mike Purcell, CA Energy Commission

The Status of Natural Gas Development in Northern California
Rob Habel, California Department of Oil, Gas and Geothermal Resources

Eliminating Impediments to In-State Production
Rock Zierman, CIPA

TECHNOLOGY OVERVIEW

California imports 85% of the natural gas consumed in the state. At $8/MCF, that is $15 billion leaving the state each year. Every effort must be made to optimize the output of existing wells to extend their lives and to address regulatory and utility requirements that discourage new drilling.

Overview of Technologies for Dewatering Gas Wells
The pressure gradient in a gas well is composed of friction and gravity. The more the liquids build with time, the greater the gradient and the lower production. There are four defined flow regimes, of increasing gas velocity: (1) Bubble flow, in which the tubing is almost completely filled with liquid. Free gas is present as small bubbles, rising in the liquid. Liquid contacts the wall surface and the bubbles serve only to reduce the density. (2) Slug flow, in which gas bubbles expand as they rise and coalesce into larger bubbles, then slugs. Liquid phase is still the continuous phase. The liquid film around the slugs may fall downward. Both gas and liquid significantly affect the pressure gradient. (3) Slug-annular transition, in which the flow changes from continuous liquid to continuous gas phase. Some liquid may be entrained as droplets in the gas. Gas dominates the pressure gradient, but liquid is still significant. (4) Annular-mist flow, in which the gas phase is continuous and most of the liquid is entrained in the gas as a mist. The pipe wall is coated with a thin film of liquid but the pressure gradient is determined predominately from the gas flow.

In a typical gas well that makes water, the gas rate will initially decline normally and the water rate increases. As some point in time the flow regime moves through the four flow regimes above, declines rapidly and essentially dies (the gas velocity has dropped below the minimum required to move the liquids up and out of the wellbore). The problems this causes is loss of production, possible formation damage, more corrosion and the expense of artificial lift or other remediation. Water can come from a number of sources: formation water produced with the gas, water from a separate water zone, condensed from the saturated gas, or coned into the gas zone from an underlying aquifer.

There are a number of diagnostics with which to detect or predict well loading. The relative pressures of the tubing and casing when flowing and shut-in can be a good indicator. Also an Inflow Performance Relationship curve can be drawn to relate the flowing pressure to the producing rate. When a normally declining well becomes erratic, then produces at a reduced what, it is an indication of loading. Measuring the pressure gradient in the tubing vs. depth will also show loading. Finally, by computing the critical velocity at which the liquid can no longer be lifted, a critical rate versus flowing tubing pressure can be constructed for various tubing sizes. Choking a well only serves to raise the critical flow rate. The well must be above the critical rate to produce but not so great a rate that friction becomes an issue. Nodal analysis can be used to model liquid loading and study the effects of tubing size, back pressure, where to land the tubing and the effects of various artificial lifts.

Some of the popular remedies for liquid loading include venting, soaping, equalizing, stop clocking, velocity tubing strings, pumping unit, compression and plunger lift. The things that must be considered is what will provide the lowest bottom hole and casing pressure, the mechanical limitations, cost, and the operator's capabilities. Venting is easy, but loses production, pollutes and must be repeated. Soaping, to lower the liquid density and surface tension is easiest to try, but may only put off the inevitable. Equalizing is simply making the fluid level in the tubing equal to that in the casing. It usually requires some venting and doesn't remove any liquids. Stop clocking is simply producing for something less than all day to let the pressure build up and is generally a short-term fix. Velocity strings work and require no maintenance but can be expensive and generally do not work with artificial lift. Pumping units will work until abandonment, but are expensive to buy and to operate. The plunger lift can also be used for the life of the well and is less expensive than the pumping unit. However, it is more difficult to operate effectively and requires more time and expertise from the operator.

A Review of Gas Processing and a Case Processing and a Case Study
There are a number of gas processing technologies needed to render produced natural gas of pipeline quality and to capture the premium value hydrocarbon liquids and sulfur that it might contain. Some of the more common technologies are gas compression, gas sweetening and sulfur recovery, gas liquids extraction, gas dehydration, tail gas incineration, liquid petroleum gas (LPG) fractionation, and LPG storage and transfer. Gas compression may be necessary to produce the well or to meet minimum pipeline pressure. It can be done with reciprocating cylinder multi stage, rotary vane/screw, or centrifugal compressors. They will allow the removal of any condensate and control the production rate. Gas sweetening and sulfur recovery can be accomplished with solid bed absorption (iron sponge or mol sieve), chemical solvents such as amine or potassium carbonate, physical solvents such as Solfinal, or direct conversion of H₂S to elemental sulfur with Claus or other similar processes. Natural gas liquids (NGLs) are straight chain hydrocarbons longer than the single carbon methane. Like sulfur they are a marketable bi-product. They can be removed with adsorption oil (old technology), refrigeration followed by low temperature separation (a little newer), or cryogenic turbo-expander plants (latest technology). Gas dehydration is generally accomplished with glycol or solid bed adsorption. Tail gas incineration is a thermal oxydizer process. LPG fractionation is to separate the various NGLs, ethane, propane, butane, and heavier.

A case history of a new gas processing plant is presented. It is a refrigeration plant and was built in 1997 to process natural gas produced offshore California. It is a typical size and configuration with a capacity of 15,000 MCF/Day and 8,000 ppm H₂S capabilities. The inlet pressure is 400 psi and the outlet is 900 psi. and cost $18.5 million. Some of the challenges included a critical installation timing extremely stringent regulatory environment, integration into an existing facility and soil subsidence. The process from inlet to outlet encompasses all of the processing technologies discussed above.

Corrosion Control of Well Casings
There are several reasons why corrosion control is important: to preserve the asset, reduce maintenance costs, comply with laws and regulations, and to preserve the environment. Corrosion can be defined either in practical terms as the tendency of a metal to revert to its natural state, or in scientific terms as the electrochemical degradation of a metal as a result of a reaction with its environment. For example, iron oxide can be refined and milled into steel products and through corrosion, revert back to iron oxide. The essential elements are (1) the anode, material with an innate negative charge, (2) a cathode, material with an innate positive charge, (3) an electrolyte, an electrically conductive medium, and (4) an electrical connection. When all are present the current will flow in a flux from the anode to the cathode and corrosion begins. A corrosion cell can be something as subtle as foreign material, such as clay, in the sand cushion under a steel tank or poor water drainage.

Causes of corrosion in underground structures include joining of dissimilar metals, non-homogeneous soil, differential aeration and microbiological attack. All metals have a galvanic charge (measured relative to saturated Cu-CuSO₄ electrode) ranging from magnesium at -1.4 millivolts (mV) to carbon at +0.3 mV. An example of bimetatallic corrosion is the result of a current flow between a copper grounding rod on a steel tank, and the tank itself, with current flowing through the sand pad. Because the galvanic rating of steel changes over time, new steel can react with old steel. Similarly, a threaded bolt under high stress can react with a low stress area.

To prevent corrosion, cathodic protection must be applied. Corrosion occurs where the current discharges from metal to electrolyte. The objective of cathodic protection is to force the entire surface to be cathodic to the environment. This protection can be galvanic, with the current obtained from a metal with a higher energy level, or impressed current, which requires an external power source through a transformer rectifier. With galvanic protection, a magnesium or other anode is placed near the buried structure and connected electrically. It can be wired through a surface test station through which an inspector can monitor the current. With an impressed current system, the positive side of the rectifier can be connected to a number of buried anodes and the negative side connected to the pipe or casing. Depending on the geometry of the metal to be protected, the anodes can be arranged in lines, rings, or stacked vertically.

There are several well casing corrosion tests. Because of the subsurface geology with different rocks at different depths, a number of cathodic circuits can be present on the casing and field testing to establish current requirements to meet a potential criterion for cathodic protection are complicated by changes in temperature, surface conditions and the pH at the structure-to- electrolyte interface. Several analytical tools are available to measure currents and plot the current distribution so that the optimal corrosion protection can be designed. A deep anode is placed in an open hole, with surface casing only or slotted liner allowing free exchange from one subsurface aquifer to another and sealed from surface contamination. Design factors include the subsurface geology, well completion, current requirements, density and proximity of wells, interference from other CP systems, optimum anode location, and power availability. If power off of the grid is not available, wind and solar units can provide the necessary power. Finally, a casing potential profile tool can be run to estimate the rate of corrosion and the effectiveness of the cathodic protection systems. In order to run the tool, the rods and tubing must be removed and the casing cleaned of any paraffin, scale, rust and other foreign material.

An Overview of California Gas Storage Well Completions
There are 10 commercial natural gas storage fields in California, 5 in northern California, and 5 in the south. Of the four operators, two are utilities, two are pipeline and storage companies. They are all sandstone reservoirs and were originally natural gas producing fields, although some wells do produce some liquid hydrocarbons.

The natural gas is produced, purchased and collected via a system of gathering and transmission lines and injected into the fields. The gas is sold, either as a storage service or bundled full requirements service to residential, commercial and industrial customers, generally when it is very hot (generation load) or very cold (heating load). Injection rates range from 10 to 60 MMCF/day. Withdrawal rates range from 10 to over 100 MMCF/day.

The storage field depths and storage intervals range from 2,000 feet to over 8,000 feet, with thicknesses from 50 to 300 feet. Some contain more than one interval. The individual completions are vertical and horizontal and everything in between.

Most of the wells are used both for injection and withdrawal. Along with some associated water production, this cycling causes some formation degradation so that most wells require some method of sand control. The methods of controlling sand production during withdrawal include: (1) limiting production and flow rates, (2) mechanical methods such as screens or slotted liners, and (3) gravel packing with open or cased hole gravel packs. Well fracturing may utilize a sand, resin coated or deformable proppant. Frac-packing is done with a liner (usually a screen) in place. The author gives several examples of arrangement of packers, safety valves, sliding sleeves, screens and circulating shoes for cased and open holes, vertical and horizontal.

California's Natural Gas Outlook
California's natural gas outlook has good news, bad news, and optimistic news. The short term outlook holds the good news. That is (1) the current infrastructure reliability is good, (2) recent infrastructure improvements have made it even better, (3) current storage inventories are good, (4) the broad public energy dialogue has begun to focus more on natural gas issues, (5) California has started a new natural gas Research and Development program, and (6) greater use of natural gas has improved air quality. These and other related topics can be found on the state website for energy www.energy.ca.gov/naturalgas/.

The long term outlook, however, holds the bad news: (1) natural gas prices are much higher than before, (2) natural gas is the dominant fuel for generation, consuming over 25% of the total California demand, and all new electrical capacity is natural gas fueled, (3) California imports 85% of its natural gas, (4) California is at the end of the pipelines that serve it, (5) California must compete with all other major U.S. markets for their natural gas, and (6) the U.S. supply/demand balance is pessimistic, with more wells being drilled than ever, but diminishing reserves per well, essentially working increasingly harder to stay even. The EIA is predicting U.S. demand growing from 23 TCF today to 30 TCF by 2025. At $10/MMBTU, Californians pay about $22 billion just for the gas itself. A 10% reduction in demand would keep $2 billion from going out of state.

There is some cause for optimism, however. California has a number of options available in the short, medium and long term and the policy makers are focused on further improving California's position. Strategic thrusts under consideration include natural gas energy efficiency programs and standards, electricity efficiency programs, renewable energy programs, distributed generation, new sources of natural gas supply and additional natural gas infrastructure. The state recently released the 2005 Energy Report, building on the 2003 report and with the participation of a large segment of the population. The Western Governors are undertaking a study of the Adequacy Assessment of Western Natural Gas. The first phase will examine the long term. It will be a 10 year perspective based on annual average conditions, but also testing abnormal conditions. The focus will be on infrastructure and resource adequacy. It will be completed later this year. Phase two will examine monthly conditions and natural gas storage seasonality, peak demand, threats to reliability and the role of storage. It will be completed in 2006.

The Status of Natural Gas Development in Northern California
District 6 of the Division of Oil, Gas and Geothermal Resources (DOGGR) is the area of northern California. It produces 200 MMCF/day of natural gas, compared to the total state production of 900 MMCF/day. In 2004 140 drilling permits were issued, down from a peak of 225 in 1999. There are approximately 1050 producing natural gas wells, down from 1350 in 1985. An additional 500 wells are idle. In 2004, 70 development wells were drilled with a success ratio of 80%. Only 6 rank wildcats were drilled wit a 33% success rate.

The current trend is not good. The same number of wells are being drilled each year, but the reserve additions, and the production are declining; this, in the face of increasing demand. The state produces 0.9 BCF/day, but consumes 6 BCF/day, requiring imports of over 5 BCF/day. Those imports come into the state through interstate pipelines originating in Canadian, Southwestern and Rocky Mountain producing areas.

District 6 is home to half of the commercial storage facilities and just under half of the capacity. The storage fields, operators, and their capacities are:

- Lodi Gas, Lodi Gas Storage, LLC, 18 BCF
- Los Medanos Gas, P G & E, 24 BCF
- McDonald Island Gas, P G & E, 118 BCF
- Pleasant Creek Gas, P G & E, 7 BCF
- Wild Goose Gas, Wild goose Storage Inc., 15 BCF

The total inventory varies seasonally from a low of 100 BCF at the end of winter, to a high of 180 BCF at the end of the injection season in October.
DOGGR's program deals with the state laws and regulations that govern the development of oil, gas and geothermal resources to prevent damage to life, health, property and natural resources. Target operations include (1) drilling, maintenance, and plugging and abandonment operations, both onshore and offshore, (2) primary hydrocarbon and geothermal resource recovery, enhanced oil recovery, natural gas storage and waste-water disposal projects, and (3) operation for the abatement of subsidence of land overlying oil and geothermal fields. Their main goals are to prevent damage to hydrocarbon or geothermal reservoirs, environment, and other natural resources; to prevent contamination of freshwater deposits penetrated by wells; to prevent conditions that may be hazardous to life or health; and to encourage the wise development of oil, gas and geothermal resources.

Eliminating Impediments to In-State Production of Natural Gas
There are a number of barriers to the production of natural gas in California. Many have solutions that will eliminate the obstacle. The first obstacle is access to utility infrastructure. In California, unlike all other producer states, the utilities require a well to produce 50 MCF/day. The result is 200 MMCF of stranded gas, jobs and revenues lost. This could be resolved with the acquisition of P G & E's gas gathering lines. Similarly, the growing limitation to installing new infrastructure is causing projects to be abandoned or producers forced to install private systems. Legislative relief is needed to improve the situation.

The third obstacle is that the utility quality standards in Southern California are impossible to meet. Southern California producers are forced to comply with more stringent standards, including CARB specifications for fueling CNG vehicles. The zero tolerance enforcement has led to a disconnect between safety and standards. The quality standards need to be changed. Similarly, in northern California quality standards have resulted in as much as one third of the production shut in due to low BTU content. This could be overcome with private storage or providing the utilities the incentive to blend with higher BTU natural gas.

The fifth obstacle is California's regulatory and permitting process. More than 25 different local, state and federal agencies can be involved in the permitting of a single well. Delays in permitting have caused abandoning of projects or stranding of capital. This could be streamlined through a permitting workshop to educate local agency staff and help eliminate jurisdictional overlap. Lastly, producers face a barrier in free access to capital markets. Eight-five percent of new wildcats in California are drilled by independents. Delays in permitting drive down the return on investment and make capital investment in California less attractive.

CONCLUSIONS
Given today's prices and the growing need for new gas supply in California, it is vital that existing natural gas production be optimized though the elimination of technical problems such as water loading and corrosion and regulatory restrictions, such as minimum producing levels. Equally important is the elimination of impediments to new drilling and infrastructure additions. In forums such as this, producers, pipeline companies, producer organizations and the state are working together to see that that happens.
 

CONNECTIONS:

Rock Zierman
California Independent Petroleum Association
11121 I Street, Suite 350
Sacramento, CA 95814
Ph: 916-447-1185
Email: rock@cipa.org

James Lea
Texas Tech University
Dept. of Petroleum Engineering
PO Box 4311
Lubbock, TX 79409-3111
Ph: 806-742-3573
Email: james.lea@ttu.edu

John Crews
Cannon Associates
364 Pacific St
San Luis Obispo, CA 93401
Ph: 805-544-7407
Email: johnc@cannonassoc.com

Saibal Mitra
CORRPRO
13011 Florence Ave
Santa Fe Springs, CA 90670
Ph: 562-254-6205
Email: smitra@corrpro.com

Mike Gleason
Baker Oil Tools
1404 Fleet Ave
Ventura, CA 93003
Ph: 805-644-5541
Email: mike.Gleason@bakeroiltools.com

Mike Purcell
California Energy Commission
1516 Ninth Street, MS-29
Sacramento, CA 95814-5512
Ph: 916-654-4048
Email: mpurcell@energy.state.ca.us

Robert Habel
California Department of Oil, Gas and Geothermal Resources
801 K Street, MS 20-22
Sacramento, CA 95814
Ph: 916-322-1110
Email: rhabel@consrv.ca.gov

For information on PTTC’s West Coast Region and its activities contact:

Iraj Ershaghi, Director, Petroleum Engineering Program, HEDCO-316
University of Southern California, Los Angeles, CA 90089-1211
Phone 213-740-0321, Fax 213-740-0324, E-mail ershaghi@usc.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

Petroleum Technology Transfer Council, 16010 Barkers Point Lane, Ste 220, Houston, TX 77079
toll-free 1-888-THE-PTTC; fax 281-921-1723; Email hq@pttc.org; web www.pttc.org