Neuquén, Argentina

10-12 June 2014

Decline Curve Analysis in Unconventional Gas

Reservoirs with Organic Material and Adsorbed Gas

SPE Exploration and Development of Unconventional Reservoirs Conference

Castellanos-Páez, Francisco, Arevalo-Villagran, Jorge A.,

Martínez-Romero, Néstor, Pumar-Martínez, Francisco, and

Gallardo-Ferrera Erick, UNAM.

Contents

• Introduction • Background • Development • Field results • Conclusions • Recommendations

Introduction

The Arps and Fetkovich methods for decline curve analysis are commonly used tools to evaluate reservoir declination and reserves.

Decline curve analysis in unconventional gas reservoirs (UGR) with organic material content (OMC) and adsorbed gas provides results obtained from actual data to assess production behavior and volumes to be produced from unconventional shale and coalbed methane gas reservoirs.

Geographical location

1Information obtained from the EIA

Geological Period Resources (MMMMscf)

Upper Cretaceous 507

Middle Cretaceous 8

Lower Cretaceous 166

Total 681

In Mexico, La Casita and Eagle Ford have been identified as important hydrocarbon river basins of Pimienta Shale, in which it is estimated that there are potential reserves of 681 tcf, which is 22% of the reserves in America and 11% worldwide.

Contents

• Introduction • Background

• Development • Field results • Conclusions • Recommendations

Background The most commonly-used method to determine conventional reserves is decline curve analysis. Arps and Fetkovich determined that the tendency may be exponential, hyperbolic or harmonic.

Arps Function :

where:

qi is the initial rate, Di is the initial

declination and b is the declination

exponent:

b = 0 declination is exponential.

b = 1 declination is harmonic.

0 < b < 1, declination is hyperbolic.

Fetkovich Function:

1

𝑞

𝑑𝑞

𝑑𝑡= −𝐷𝑖𝑞

𝑏

𝑞 𝑡 = 𝑞𝑖𝑒−𝐷𝑖𝑡

𝑞 𝑡 =𝑞𝑖

1 + 𝑏𝐷𝑖𝑡1𝑏

There are several modifications to the methods in order to apply them to unconventional formations, taking into account the following:

1) A sharp decline rate at short production times. 2) Gas adsorption and desorption effects in organic matter. 3) High water production volumes at the beginning of well production.

Background The behavior of unconventional reservoirs differs from conventional ones, especially during early production stages when the water from the completion stage is being produced. Because they contain organic matter and adsorbed gas, it is important to know the type of gas adsorption isotherm as well as the pressure, since the OGIP varies and the gas desorption modifies the declination behavior.

𝑽𝒂 =𝑽𝑳𝒑

𝒑𝑳 + 𝒑

Background Taking into consideration formation pressure and Langmuir pressure and volume, the Langmuir model was applied to determine the quantity of adsorbed gas in the organic material and to evaluate how the desorbed gas modified the production decline curve. In order to obtain estimates of the gas volumes to be produced from the well, actual production data were adjusted using the Arps and Fetkovich methods,

Background Several models have been developed to fit the diverse behaviors that may occur in unconventional gas reservoirs.

Models and equations

Arps 𝑞 𝑡 = 𝑞𝑖𝑒−𝐷𝑖𝑡; Exponential

𝑞 𝑡 =𝑞𝑖

1+𝑏𝐷𝑖𝑡1𝑏

; Hyperbolic

Power Law 𝑞 𝑡 = 𝑞 𝑖𝑒𝑥𝑝 −𝐷∞𝑡 − 𝐷 𝑖𝑡𝑛

Declination Function: D(t)

𝐷 𝑡 = −1

𝑞

𝑑𝑞

𝑑𝑡≈ 𝐷∞𝑡 − 𝑛𝐷 𝑖𝑡

− 1−𝑛

Hyperbolic Function: b(t)

𝑏 𝑡 =𝑑

𝑑𝑡

1

𝐷 𝑡≈

𝑛𝐷 𝑖 1 − 𝑛

𝑛𝐷 𝑖 + 𝐷∞𝑡1−𝑛 2

Valkó 𝑞 𝑡 = 𝑞 𝑖𝑒𝑥𝑝 − 𝑡 𝜏 𝑛

Jones and Arps

𝑞 𝑡 = 𝑞𝑜𝑒𝑥𝑝−𝐷𝑜𝑡

𝑚−1

100 𝑚 − 1

1

1

Contents

• Introduction • Background • Development

• Field results • Conclusions • Recommendations

Development The first well is located in the Eagle Ford formation in the U.S. The other two are in the southern portion of the formation, located in Mexico.

For the well analysis, the production pressure data were smoothed using as the outset of declination the maximum production, beside converting the produced water to its gas equivalent so the total production corresponds to the total pressure drop in the formation.

Later, the models declinations were adjusted through regressions, and last, there were made predictions to 15 years and new adjustments incorporating desorbed gas, considering an instant desorption, and the hole released gas production.

General Data from the Eagle Ford Formation

Depth: 2,500 - 14,000 ft

Thickness: 50 - 300 ft Pressure Gradient: 0.4 - 0.8 psi/ft TOC: 2 - 9% Gas Saturation: 83 – 85% Permeability: 1 - 800 nd

Isotherm for Eagle Ford

Contents

• Introduction • Background • Development • Field results

• Conclusions • Recommendations

Field results Well A Well A produces dry gas and is located in the Eagle Ford shale formation in southern Texas. It was completed with a 4,000 ft. horizontal geometry and a ten-stage stimulation treatment consisting of 20 transversal lateral fractures, generating a 169 MMft3 Stimulated Reservoir Volume (SRV).

Data analysis: ɣg = 0.596 VL = 75 scf/ton pc desor = 3500 psia

MN2 = 0 pL = 656 psia ρr = 1.3 gr/cm3

MCO2 = 0 pi = 5100 psia SRV = 16900000 ft

MH2S = 0 Vai = 66.4523975 scf/ton mroca = 622599.1534 Ton

T = 207 °F Gai = 4.14E+07 scf/ton

Well Declination Match qg Prediction to 15 years

Field results Well A

Match t = tD = 1.2

Match q= qDd = 192

b = 0.81

qi = 5.208 MMscf

Di = 0.012000 días-1

Gp = 1.59 Bcf

Well A Fetkovich Match

Modelo Gp (Bscf)Arps Exp 0.85Arps Hip 2.79PLE 1.27Fun Hip 1.39Valkó 1.27Jones 1.27

Field results Well A

Shale well B was drilled and completed with a horizontal geometry in Eagle Ford’s upper Cretaceous formation, with a vertical depth of 8,300 ft and a horizontal path of 13,356 ft.

During its completion, 17 fractures were made with 856 ft in length, 459 ft in height, and an average width of 0.8 in.

Pressure-production history of Shale B well. General data from Shale B well.

VL = 60 scf/ton ρr = 2.8 gr/cm3 PL = 250

SRV = 446 MMft3

T = 207 °F mr = 35280000 Ton φ = 0.06

Well radius, ft 0.375

Lateral length, ft 1837

Thickness, ft 492

Depth, TVD, ft 2530

Hydrocarbon porosity (%) (φhc = φef (1-Sw))

6.0

Reservoir pressure, psia 5,100

Temperature, °R 667 Gas compressibility, 10-4 psia-1 1.3 Gas viscosity, cp 0.0239

Number of effective fractures 8 Stimulated Reservoir Volume (SRV) (MMft3)

445

Desorption data

Field results Well B

Well Declination Adjustement qg Prediction to 15 years

Field results Well B

Well B Fetkovich Match

Match t = tD = 0

Match q= qDd = 0

b = 0.66

qi = 4.484 MMscf

Di = 0.007500 días-1

Gp = 1.54 Bcf

Modelo Gp (Bscf)

Arps Exp 0.74

Arps Hip 1.55

PLE 1.08

Fun Hip 1.11

Valkó 1.08

Jones 1.08

Field results Well B

Shale well C was drilled and completed with a horizontal geometry in Eagle Ford’s upper Cretaceous formation, with a vertical depth of 5397 ft and a horizontal path of 11,270 ft.

During its completion, 16 fractures were made with 528 ft in length, 380 ft in height, and an average width of 0.82 in.

Pressure-production history of Shale B well. General data from Shale B well.

VL = 60 scf/ton ρr = 2.8 gr/cm3 PL = 250

SRV = 446 MMft3

T = 207 °F mr = 35280000 Ton φ = 0.06

Well radius, ft 0.375

Lateral length, ft 11,270

Thickness, ft 215

Hydrocarbon porosity (%) (φhc = φef (1-Sw))

6.0

Reservoir pressure, psia 3294

Temperature, °R 632 Gas compressibility, 10-4 psia-1 2.6

Number of effective fractures 16

Stimulated Reservoir Volume (SRV) (MMft3)

671

Desorption data

Field results Well C

Well Declination Adjustement qg Prediction to 15 years

Field results Well C

Well C Fetkovich Match

Modelo Gp (Bscf)

Arps Exp 1.07

Arps Hip 5.59

PLE 1.30

Fun Hip 1.56

Valkó 1.13

Jones 2.65

Field results Well B

Match t = tD = 0.21

Match q= qDd = 490

b = 0.061

qi = 2.041 MMscf

Di = 0.002100 días-1

Gp = 1.03 Bcf

Match t = tD = 0.21

Match q= qDd = 490

b = 1.00

qi = 2.041 MMscf

Di = 0.002100 días-1

Gp = 5.17 Bcf

Case 1 Case 2

Desorption case

Field results Well B

For match of de curve producton we use the Arps and Jones Models. Arps Hip Jones Arps 𝑞 𝑡 = 𝑞𝑜𝑒𝑥𝑝

−𝐷𝑜𝑡𝑚−1

100 𝑚 − 1

𝑞 𝑡 =𝑞𝑖

1 + 𝑏𝐷𝑖𝑡1𝑏

Match parameters

Aprs Hiperbolic Model

Free gas Desorption gas

qi [Mscf/d] = 3359 4139 Di [1/d] = 0.0085 0.0078

b = 0.9711 0.8834

Field results Well B

Arps Hip Model

𝑞 𝑡 =𝑞𝑖

1 + 𝑏𝐷𝑖𝑡1𝑏

Arps Hip Model

Free gas Desorption gas

qg [Mscf/d] = 3708 4691

Do [ 1/dm]= 2.6931 2.7394

m = 1.5977 1.5977

Match parameters Arps - Jones Model

Jones Model

𝑞 𝑡 = 𝑞𝑜𝑒𝑥𝑝−𝐷𝑜𝑡

𝑚−1

100 𝑚 − 1

Model Gpf (Bscf) Gpt (Bscf) ΔGp (%) Arps Exp 0.730 0.891 18 Arps Hip 1.550 1.756 12

PLE 1.078 1.238 13 Fun Hip 0.740 0.885 16

Valkó 1.080 1.239 13 Jones 1.080 1.250 14

General results

Field results Well B

Jones Model

Contents

• Introduction • Background • Development • Field results • Conclusions

• Recommendations

Conclusions

1. The best models for estimation of rate and EUR to recover are those of Jones-Arps, PLE and Valkó. However this may change according to the decline of each well.

2. Is a necessary condition that the wells produce in pseudosteady state regime, since otherwise errors in calculations and predictions will be high.

3. It was confirmed that the gas adsorbed on the Eagle Ford Formation in Mexico is between 15% - 20%, so it is important to consider when calculating the EUR. In addition to reducing the desorbed gas production decline.

4. When considering the effects of adsorbed gas combining the Langmuir model with the declinations methods, even more accurate well production behavior results were obtained, which lead to more optimistic estimates of the gas volumes to be produced.

Contents

• Introduction • Background • Development • Field results • Conclusions • Recommendations

Recommendations

1. Properly characterize the gas and training to obtain correct values of the Langmuir isotherm and the desorption pressure.

2. To properly determine the decline of the well and the EUR is advisable to compare the results of the analytical models with Matter of Balance and Numerical Simulation.

3. In cases in which the adsorption of gas in the formation is present, to improve the fit of the declination and production forecasts, is necessary considering the time for desorption of gas, and its recovery factor.

4. Because the Eagle Ford formation no high levels of gas adsorbed, it is recommended to optimize the costs of drilling and completion of wells.

Decline Curve Analysis in Unconventional Gas

Reservoirs with Organic Material and Adsorbed Gas

SPE Exploration and Development of Unconventional

Reservoirs Conference