This Series of Guides Addresses:

Transcription

1 Fracturing What are you calling fracturing? Transport of materials to the well site? Surface equipment and pumping operations? Surface pressure control of the well during drilling or production? Well construction issues where insufficient barriers fail? Fracturing the pay zone? Simple fact 1 million frac jobs have been pumped since the late 1940 s and there is no documented case of a frac breaking up through thousands of feet of rocks to pollute a fresh water zone. However, there are cases of: Poorly constructed or maintained wellbores leaking into an aquifer, mostly during production. Leaks at surface during pumping due to failure of surface equipment. Infrequent spills of water and some chemicals at surface from transport accidents or equipment failures. Questions to ask: What is being spilled? What is the frequency? Can it be prevented? How is it being cleaned up?

2 This Series of Guides Addresses: Fracturing what it is, what it isn t and is it necessary? Chemicals in Fracs what, how much what happens to it? Water Management use, backflow, content, treating, risks. Drilling how the well is drilled, what is used, risks. Well Construction effective barriers and monitoring. Multi-Well Pads advantages and disadvantages. Surface Pressure Containment blow out preventers or BOPs. How Fluids Flow in the Reservoir. How Fluids Flow in the Well. Each guide uses basic terms and references risks, monitoring actions and performance indicators.

3 Why Fracture? Fracturing is required in nearly all currently developing on-shore US gas reservoirs to make the wells commercial. Without fracturing, an average gas shale well will not produce more energy than it takes to keep it flowing (running pumps to keep the condensed water out). A fractured shale gas well may produce ½ billion scf of gas in a 5 year period or enough to power, cool and heat ~500 homes for 5 years or to run two thousand cars for five years (10,000 miles/car/yr). Without fracturing, the US gas production is predicted to fall by an estimated 17% per year. With fracturing and horizontal wells, the recoverable US gas production will rise by 88% in the next 5 years. The US is extremely rich in natural gas that is locked in low permeability reservoirs. This requires fracturing to produce.

4 The effect of fracturing on production Basically, fracturing in low and ultra-low permeability formations (shale) is the only effective means of generating a flow rate that achieves both well unloading (stable production) and economic payback.

5 What does a fracture look like? Fractures are breaks in the rock, created by fluid under pressure, overcoming the insitu formation stresses and starting a small crack at the wellbore, then enlarging that crack by pumping water at high rates. Right: a fracture forming perpendicular to least principle stress s hx. Left: a real fracture, <0.1 wide, at a depth of 1740 ft. These vertical fracs can be halted at even small barriers such as the shale streak and need access to the formation to start again.

6 What limits a fracture s growth? A fracture may grow outward (length), up and down (height) and slightly wider until it meets a barrier or runs out of driving force (fluid pressure). 1. A frac barrier is another formation with sufficiently different properties that it will not fracture with the available forces in the frac. 2. Driving force is supplied by the injection rate: when the leakoff rate into the formation equals the fracture injection rate, the fracture stops growing.

7 If barriers are present? Frac barriers may contain a frac so that it does not generate significant height growth. This is common in the Barnett shale formation sequence and in all other formations. How is it monitored? Microseismic, logging tools, tilt meters, mine-back experiments, pressure behavior, etc. SPE

8 Fracs Self-Limited by Frac Fluid Leakoff Take the previous fracture: with 2 wings (each side of the wellbore) and 2 formation faces exposed to leakoff along the frac. The area is 650 x 95 x 2 x 2 = 247,000 ft 2 At a high pump rate (100 bbl/minute), the water injected would be 0.29 ounces per minute per ft 2 of formation area. If the leakoff into the matrix or the natural fractures is more than this, the frac will stop growing.

9 The bottom line? It is very difficult to get a fracture to grow to more than 300 ft of total height. Nearly all gas productive shales are at depths of 4000 to ft deep. The depth of the deepest fresh or even usable water zone is about 800 ft.

10 How is a Frac Designed? Refined and complex fracture models predict from rock mechanics how fractures will form. Are they accurate? The frac predictions are as probably as accurate as the input data on formation stresses, barriers, rock types, laminations, etc. Frac Model Shape Prediction Output Right: width profile of affected area. Far Right: length and height predictions. SPE

11 Formation Stresses Shape the Fracture The stress profile The stress profile created by the formation is measured using sonic logs and the data is used in the frac model.

12 Microseismic Monitoring of Fracs in a Horizontal Well Microseismic listens for the sound of stress release during fracturing (breaking rock) and triangulates to an approximate location of the sound. For this twelve stage frac (SPE ), the fracture height self-limited at a few hundred feet, even though no fracture barriers were yet encountered.

13 Fracture Growth and Breakout Indicators Temperature Logs in Vertical Well see the temperature produced from the water in the frac. Microseismic an expensive monitoring method that may be done from the surface in some cases or from another near-by wellbore. Tilt meters sensitive enough to detect earth tides produced from the moon passing overhead, can show fracture direction and growth. Tracers chemicals measured in the parts per billion can be used to measure leakoff and returns or breakthroughs to other zones or wells. Surface Pressure Behavior pumping pressure, annulus pressure, adjacent wells, etc., are the best sources of realtime, direct measurements. In this area, nothing beats experience.

14 Rock Fracturing Risks Breakout to a nearby well in the pay zone (grows outward, not upward) relatively common if the wells are close (<500 ft) and in line along the frac direction. Screenout rare, perhaps ~2% of jobs, PRD s (pressure relief devices) vent the pressure and fluids to a catch tank if needed. Packer or seal unseats downhole and backside pressures up: rare, probably < 0.5%. Generally no losses to the upper formation. Rupture of the well casing or breakdown of cement exceedingly rare, perhaps <1 in 10,000 (very few known cases). Job stops immediately and fluid lost out of pay is usually < 100 bbls. Fracture breaks through rock to surface or fresh water? No documented case known.

15 Other Risks Transport depends on drivers, roads and conditions area specific, but definitely controllable. Pumping spills maybe 1% of jobs will have a reportable spill usually water. Loss of surface pressure (spill) during plug drill-out or cleanout (BOP on the well) rare maybe 1 in 500 jobs.

16 A Quick Look at Shale Frac Materials (there is a separate presentation for chemicals) Frac Fluid Most fracs fluids are water based. Proppant sand and a few man made ceramics, washed & graded into size ranges Friction Reducer polymers (food grade) Biocides swimming pool shock is typical Scale inhibitors, ph adjustments, gelling agents (polymer), cross-linkers, etc. usually very low concentrations see the section on chemicals. Water (all forms) Sand Chemicals Water = 95.3% Sand = 4.6% Chemicals = 0.12% Total weight of chemicals on location is usually 20,000 to 30,000 lb, much of it water base weight

17 Where do the chemicals end up? Polymers often break down into small chains and are attacked by bacteria in the flowback water or treating plant. Chlorine based biocides spend on biogenic materials and come back as chloride ions. Surface active materials commonly adsorb on the mineral surfaces and do not return in measurable amounts. 15% to 50% of the water returns over 2 to 6 weeks, the rest is adsorbed and absorbed into mineral structures in the formation. Many chemical additives adsorb on the charged, high surface area clays and do not return in the flowback.

18 Proppant sand or man made (ceramic). Keeps the fracture open to improve flow. There may be several million pounds of sand in a frac. It can be tagged with short life isotopes (zero-wash).

19 Frac Fluid Flowback Salt water makes up 99.9%+ of the fluid flowed back after a frac job. About 15 to 50% of the water comes back and must be separated and treated (another section on this topic). After dilution and treating much, if not all, of this water can be reused for fracturing.

20 Why is there methane gas in my water well?!!!! Biogenic methane is extremely common in shallow formations, including those that contain fresh water recharged from the atmosphere and anywhere else where biologic activity is occurring. Both biogenic and thermogenic gas seeps are common throughout North America (1100 known on shore and 600 known offshore Gulf of Mexico). World wide natural gas seeps are known to contribute 50 to 70 million tons of methane per year to the atmosphere and shallow formations that s 2600 to 3600 Bcf per yr or 7 to 10 bcf/day. Many of the natural gas seeps are centered in areas of shallow to deep hydrocarbon production including Pennsylvania, New York and Colorado. BTW - Some of the largest natural oil seeps in North America are in California, many in the Santa Barbara channel.

21 Biogenic vs. Thermogenic Gas Biogenic methane is isotopically lighter, or more depleted in the carbon 13 isotopes than thermogenic methane. Thermogenic methane has more C13 but no C14 (radioactive isotope)

22 US Natural Gas Use ( EIA) Electric Power Generation Industrial Residential Commercial Lease and plant fuel Pipeline and distribution Vehicle Fuel 6.7 tcf 6.7 tcf 4.9 tcf 3.1 tcf 1.3 tcf 0.6 tcf 0.03 tcf 23 tcf/yr or 63 bcf/day for bcf/d EIA estimate for 2010