WELL STIMULATION ADVANCES

Based on a workshop co-sponsored by PTTC's North Midcontinent Region and the Wichita Chapter of Society of Petroleum Engineers on February 9, 2000 in Wichita, KS

BOTTOM LINE

Advances in well stimulation—matrix acidizing, fracture acidizing, hydraulic fracturing, extreme overbalance operations—enable operators to optimally increase well/ reservoir productive capacity. Experience-based guidelines, shared by vendors, for effective stimulation of Morrow, Chase/ Council Grove, and Granite Wash reservoirs in western Kansas provide operators a leg up when designing stimulation treatments. Organic damage removal with chemicals can be a solution for many older wells with impaired production.

PROBLEM ADDRESSED

Current economic conditions dictate that operators maximize well/ reservoir productivity. Well stimulation is not new-wells have been acidized and hydraulically fractured for decades. However, there have been many advances both in knowledge of the stimulation processes and the technology incorporated in them. Although not expected to become stimulation experts, all operators must know the basic thrust of stimulation technology and recent advances to more effectively design and interact with the service company community.

KEY WORDS:

Acid fracturing, Chase/ Council Grove, Extreme overbalance, Matrix acidizing, Morrow, Organic damage removal, Tip screenout fracturing

SPEAKERS

Matrix and Fracture Acidizing Principles
Bill Johnson, Halliburton Energy Services

A Major's Experience with Well Stimulation
Carl Montgomery, Arco E& P Technology

Morrow & Chase/Council Grove; High Perm Fracturing
Larry Britt, NSI Technologies

Granite Wash; Extreme Overbalance Operations
George Waters, Dowell Schlumberger, Inc.

Organic Damage Removal, Ken Barker, Baker Petrolite

TECHNOLOGY OVERVIEW

Two basic types of acidizing operations can be conducted: (1) Matrix acidizing is performed below fracturing rate and pressure. Acid flow is through the matrix with reactions being in existing pores and natural fractures. (2) Fracture acidizing is performed above fracturing rates and pressures. Etching of the created fractures provides well stimulation, not just damage removal.

Matrix Acidizing Principles. Matrix acidizing enhances well productivity by reducing the skin factor through either removing near-wellbore damage or superimposing a highly conductive structure onto the formation. It is not a solution for poor reservoir quality. Typically, the lower per meability limit is about 10 mD for an oil well and 1 mD for a gas well. In carbonates, acids react with flow channels and pores and can create long wormholes, effectively increasing permeability for several feet in the reservoir. In contrast, acid treatments in sandstones merely remove damage and do not actually stimulate the reservoir. Carbonates, which tend to be less homogeneous than sandstones, often contain natural fractures. Acid can open natural fractures by reacting more quickly with fracture infilling material, causing unexpected high production rates after matrix acidizing treatments.

There are three distinct dissolution regimes in carbonates:

• Compact dissolution occurs when the acid spends on the face of the formation.
• Uniform dissolution occurs when acid reacts under the laws of fluid flow-penetration will at most be equal to the volumetric penetration of the acid.
• Wormholes develop when acid invasion is uneven, causing highly conductive channels to develop. Wormholing (which is preferred in carbonate reservoirs) depends on surface reaction rate, acid diffusion rate, and acid injection rate. For any given set of conditions, a critical velocity exists below which wormholes will not form.

There are four basic types of matrix acidizing treatments:

• Wellbore cleanouts merely connect the wellbore to the formation. Volumes typically range from 10 to 25 gal/ft, treated by spotting, soaking or circulating, or small bullhead treatments.
• Near-wellbore stimulation treatments, which use larger 25 to 50 gal/ft treatments, improve permeability within 2 to 3 ft of the wellbore.
• Intermediate matrix stimulation treatments, which use 50 to 150 gal/ft, can reach 3 to 6 ft within the reservoir.
• Extended matrix acidizing treatments, which use 150 to 500 gal/ft, can result in production improvements comparable to hydraulic fracturing.

Design considerations include candidate selection, well completion, and treatment design and execution. Zonal coverage becomes a critical issue in horizontal wells or large carbonate intervals. Fluid selection begins with a review of the formation characteristics: rock composition, structure, permeability, porosity, and strength. Other factors which must be considered are reservoir fluid properties, temperature and pressure, and any limitations on injection rates. Critical additives, among the hundreds that are available, include an acid corrosion inhibitor, a surfactant, and iron-control packages.

Fracture Acidizing Principles. Acid solubility of the formation is a key factor influencing whether fracture acidizing or proppant treatments should be employed. If the formation is less than 75% acid soluble, proppant treatments should be used. For acid solubilities between 75 and 85%, special lab work can help define which approach should be used. Above 85% acid solubility, fracture acidizing would be the most effective approach. Treatment volumes for fracture acidizing are much larger than for matrix acidizing treatments, being as high as 1,000 to 2,000 gal/ft of perforated interval.

There are four primary fracture acidizing techniques:

• Fluid-loss control strives to contain the acid in natural/ created fractures.
• Conductivity enhancement pumps a viscous fluid padpumped ahead of the acid to generate a fracture geometry. Subsequent acid injection then fingers through the viscous pad. The process results in longer acid penetration distances and more effective conductivity at a greater distance along the induced fracture.
• Etched height control uses fluid density differences to control fluid placements, such as avoiding water-producing zones or gas caps.
• Tailored treatments may include foamed acids, heated acids, zonal coverage acid, and closed-fracturing acid.

Fluid-loss control is critical for achieving a good fracture acidizing treatment. Acid leakoff can be controlled by viscosifying the acid, adding solid particulates, or using alternate stages of acid and nonacid fluids. Methods for thickening acid include emulsified acid, foamed acid, polymer gelled acid, and surfactant gelled acid. Silica flour and 100-mesh sand are common solid particulates.

In larger intervals, acid diversion is important, otherwise only the interval which breaks down or fractures first will be treated. Diversion can be achieved with packers and bridge plugs (if the interval was perforated in separated groups), Perfpac balls, and granular materials. Perfpac balls allow more than one interval to be fractured during a single treatment without halting fluid flow. Common granular agents for diversion include rock salt, graded rock salt, benzoic acid flakes, wax beads, wax buttons, or oil-soluble resin material. For efficient cleanup, the producing fluids must dissolve the diverting agent at bottomhole temperature. Thus, oil-soluble resins are not used in injection/ disposal wells, and water-soluble diverting agents should not be used in oil/ gas wells unless they simultaneously produce some water.

Fracturing in High Perm Formations. Hydraulic fracturing in high perm reservoirs has grown to nearly 20% of the world wide fracturing market. Unlike conventional fracturing in tight reservoirs, the design objective for high permeability reservoirs is to generate conductivity and not length. Techniques for improving fracture conductivity fall into two groups—those that increase fracture permeability and those that increase fracture width. Proppant type, size, and concentration influence fracture permeability which varies significantly as a function of closure stress. Increasing proppant concentration and size both increase fracture conductivity. Fluid cleanliness also affects permeability—factors of concern are formation and proppant fines and residues (gels, fluid loss additives, etc.). Fracture modeling software are essential for helping define the optimum economic design for a given well. Tip screenout fracturing involves deliberately causing proppant to bridge at the fracture tip through pad depletion. Further fracture propagation ceases and continued pumping increases the fracture width. Initial minifracs are required since knowledge of fluid leakoff is critical to the development of a tip screenout.

Extreme Overbalance Operations. High pressure surges with extreme overbalance operations use existing perforations to create and extend fractures, essentially performing a mini-fracture treatment. From 300 to 1000 ft of fluid over the perforations provide mass to the surge, while pressurized gas (typically nitrogen) delivers the energy. Over 50,000 cf of gas is recommended whenever possible. The goal is to achieve a gradient greater than 1.1 psi/ ft. Treatments can actually stimulate reservoirs, providing a negative skin, although production increases may not last beyond a year.

A Major's Experience with Well Stimulation. Recent years have seen a marked increase in well stimulation activity (acid and frac jobs) within Arco with the number of treatments performed more than doubling from 1990 through 1997. In Arco's 1994 activity, 79% of the jobs were acid jobs, but since they are lower cost than fracturing treatments, they only consumed 20% of the dollars spent for well stimulation. For acid jobs, the observed failure rate was 32%. Failure rate for the less frequent but more expensive fracturing treatments was much lower, only 5%. In analyzing the reasons for job failure, one-third were due to incorrect field procedures, while two-thirds were attributed to incorrect design or improperly identifying well damage. Modeling software has proven to be an essential tool for job design and execution.

In general, two new trends are emerging—cavity completions in weak rock and using fracturing treatments for sand control. Prior practice has been to restrict sand production. An evolving school of thought is to encourage sand production and increase productivity through reduced formation damage and enhanced near-wellbore permeability. Cavity completions in weak rock can exhibit skin factors from -2 to -4 with productivity indexes to 15. Frac and Pack treatments can deliver productivity indexes of 3 to 15. Both options, when properly applied, are more effective options than typical gravel packs with productivity indexes from .5 to 2.

Fracture Stimulating Reservoirs in Western Kansas. For the deeper Morrow gas reservoirs in western Kansas, tip screenout designs show an economic advantage over conventional fracture designs. For the Chase and Council Grove formations in the Hugoton area, conventional fracture designs (high sand concentrations, large sand, and clean fracturing fluids) are favored. The shallower depth and lower stress on the proppant allow conventional designs to provide adequate conductivity. Production performance with conventional designs are nearly as good as with tip screenouts, and costs are significantly lower—less than half.

Because of their complexity, special completion/ stimulation techniques are required for Granite Wash reservoirs in the Anadarko Basin. They are typically coarse arkosic clastics. Where trapping is primarily structural, but reworking can create lenticular sands. Diagenesis plays a role in the porosity and permeability distribution. Conventional porosity logs typically overestimate net pay, so Formation MicroImaging logs are critical for more correctly estimating net pay, as well as fracture orientation. Dipole sonic logs are good for estimating stress profiles, which are important to evaluating/controlling fracture height. Non-damaging, low viscosity fluids provide excellent proppant transport, maximizing length and minimizing height growth. Preand post-fracture modeling are important to designing and evaluating individual fracture treatments.

Removing Organic Wellbore Damage. Paraffin deposition problems are frequently seen in the formation, pump, and tubing of wells with formation temperatures of <150º F . Formation plugging with paraffin in wells with bottom hole temperatures >200º F is not usually considered a possibility. Work on two wells in Southern Oklahoma was discussed. The work shows that not only is paraffin damage possible at these higher temperatures, but it is likely, if large volumes of gas are produced early in the life of a well and the crude oil contains high melting point paraffin. Large pressure drops in high temperature formations may be responsible for rapid production decline related to deposition of high melting paraffin. If unrecognized, this deposition will cause rapid production decline that may go untreated. Case histories are presented on problem analysis, testing and treatment for removal, and inhibition of production problems on two wells.

CONNECTIONS:

Carl Montgomery, Arco E& P Technology
2300 West Plano Parkway, Plano, TX 75075
Phone 972-509-3393, Fax 972-509-3283, E-mail racdog1@aol.com

Bill Johnson, Halliburton Energy Services
210 Park Avenue, Suite 2000, Oklahoma City, OK 73102
Phone 405-231-1800, F ax 405-231-1849, E-mail Johnson, Bill@Halliburton.com

Ken Barker, Baker Petrolite
369 Marshall Avenue, St. Louis, MO 63119-1897 
Phone 314-968-6001, Fax 314-968-6013, E-mail Kenneth. barker@bakerpetrolite.com

Larry Britt, NSI Technologies, Inc.
7030 S. Yale, Suite 502, Tulsa, OK 74136
Phone 918-496-2071, Fax 918-496-2073, E-mail lkbritt@nsitech.com

George Waters, Dowell Schlumberger, Inc.
6601 Broadway Ext., Suite 200
Oklahoma City, OK 73116-8214
Phone 405-840-1621, Fax 405-848-4521, E-mail waters@Oklahoma-City.oilfield.SLB.com

For information on PTTC’s North Midcontinent Region and its activities contact:
Rodney Reynolds, Project Manager, Energy Research Center, and Petroleum Engineer
Tertiary Oil Recovery Project, University of Kansas
1930 Constant Ave., Lawrence, KS 66047
Phone 785-864-7398, Fax 785-864-7399, E-mail reynolds@cpe.engr.ukans.edu

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