FracFit Solution Increased Barrels-per-foot 44% Over ... - Baker Hughes
CASE HISTORY
| bakerhughes.com
FracFit Solution Increased Barrels-per-foot 44% Over Nearby Offset
Cumulative oil per foot of lateral (bbl/ft)
Location: Eagle Ford Shale, Texas
0.7
Results
Optimized well
0.6
44% improvement
Non-optimized well
0.5
nnIncreased
initial production by 44% (bbl/ft) well-over-well
0.4
nnOutperformed
offset well despite the lateral being 2,000 ft (609 m) shorter
0.3 0.2
nnIdentified
high-stress zones, natural fractures, and like-type rock
0.1 0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Days of production The well optimized with the FracFit solution produced 44% more per lateral foot during the first two weeks of production than the non-optimized, geometric well.
nnPredicted
existence and location of high pressure zones
nnEliminated
risk of screenout
Challenges nnProve
An operator in the Eagle Ford Shale region of Texas needed to improve production from a horizontal exploratory drilling program in order to secure a substantial investment for a multi-well development program. Faced with limited in-house resources and a short time frame, the operator was under pressure to quickly and economically drill, stimulate, and produce the wells. Based on the operator’s plan for the first well, a 7,000 ft (2133 m) lateral was drilled, and the placement of fracture stages and perforation clusters was determined geometrically. When drilling the second well, however, wellbore instability issues were encountered farther down the lateral. These issues prevented the operator from drilling the final 2,000 ft (609 m) of planned lateral. To further complicate matters, high-stress zones and high downhole pressure made it
difficult to fracture the rock and would require the use of high fracturing treatment pressures. The high risk of screenout posed an overall threat to the project. Baker Hughes designed a holistic FracFit™ fracturing optimization solution to characterize the shorter lateral for maximum production. Geomechanical analysis conducted by Baker Hughes confirmed the lateral was properly oriented and recommended a completion design that would lead to optimal production. The lateral was characterized using the XMAC™ F1 acoustic logging service with the deep shear wave imaging (DSWI) processing service, and cuttings analysis. Identification of the high-stress zones, natural fractures, and like-type rock enabled the operator to optimally place the fracture stages and perforation clusters. Accurate prediction of
reserves despite reduced lateral length
nnMitigate
high screenout risks
nnManage
high-stress zones requiring high fracturing treatment pressures
nnEffectively
fracture despite high downhole pressure
Baker Hughes solution nnFracFit
fracturing optimization solution –– XMAC F1 acoustic logging service –– DSWI processing service –– Cuttings analysis
CASE HISTORY the lateral’s high pressure zones let the operator avoid screenouts while achieving a better fracture with more uniform distribution of the fracturing fluid and proppant.
During the first two weeks of production, the optimized well was producing 44% more oil per lateral foot. This allowed the operator to improve its production over its offset well, which had a lateral that was approximately 2,000 ft (609 m) longer.
Production from the exploratory program indicated there were sufficient reserves to justify financing for the larger multi-well development program.
Identified similar stress zones with ~2,000 psi variance in the same lateral XMAC F1 service with DSWI processing identified formation features up to 100 ft away from the wellbore
Identified naturally fractured areas and like-type rock for optimal cluster placement
Cuttings analysis provided mineralogy, lithology, and rock brittleness information
The FracFit solution helped the operator identify the high-stress zones, natural fractures, and like-type rock for optimal placement of the fracture stages and perforation clusters.
Disclaimer of Liability: This information is provided for general information purposes only and is believed to be accurate as of the date hereof; however, Baker Hughes Incorporated and its affiliates do not make any warranties or representations of any kind regarding the information and disclaim all express and implied warranties or representations to the fullest extent permissible by law, including those of merchantability, fitness for a particular purpose or use, title, non-infringement, accuracy, correctness or completeness of the information provided herein. All information is furnished “as is” and without any license to distribute. The user agrees to assume all liabilities related to the use of or reliance on such information. BAKER HUGHES INCORPORATED AND ITS AFFILIATES SHALL NOT BE LIABLE FOR ANY DIRECT, INDIRECT, SPECIAL, PUNITIVE, EXEMPLARY OR CONSEQUENTIAL DAMAGES FROM ANY CAUSE WHATSOEVER INCLUDING BUT NOT LIMITED TO ITS NEGLIGENCE.
© 2016 Baker Hughes Incorporated. All rights reserved. 43690 02/2016
| bakerhughes.com
FracFit Solution Increased Barrels-per-foot 44% Over Nearby Offset
Cumulative oil per foot of lateral (bbl/ft)
Location: Eagle Ford Shale, Texas
0.7
Results
Optimized well
0.6
44% improvement
Non-optimized well
0.5
nnIncreased
initial production by 44% (bbl/ft) well-over-well
0.4
nnOutperformed
offset well despite the lateral being 2,000 ft (609 m) shorter
0.3 0.2
nnIdentified
high-stress zones, natural fractures, and like-type rock
0.1 0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Days of production The well optimized with the FracFit solution produced 44% more per lateral foot during the first two weeks of production than the non-optimized, geometric well.
nnPredicted
existence and location of high pressure zones
nnEliminated
risk of screenout
Challenges nnProve
An operator in the Eagle Ford Shale region of Texas needed to improve production from a horizontal exploratory drilling program in order to secure a substantial investment for a multi-well development program. Faced with limited in-house resources and a short time frame, the operator was under pressure to quickly and economically drill, stimulate, and produce the wells. Based on the operator’s plan for the first well, a 7,000 ft (2133 m) lateral was drilled, and the placement of fracture stages and perforation clusters was determined geometrically. When drilling the second well, however, wellbore instability issues were encountered farther down the lateral. These issues prevented the operator from drilling the final 2,000 ft (609 m) of planned lateral. To further complicate matters, high-stress zones and high downhole pressure made it
difficult to fracture the rock and would require the use of high fracturing treatment pressures. The high risk of screenout posed an overall threat to the project. Baker Hughes designed a holistic FracFit™ fracturing optimization solution to characterize the shorter lateral for maximum production. Geomechanical analysis conducted by Baker Hughes confirmed the lateral was properly oriented and recommended a completion design that would lead to optimal production. The lateral was characterized using the XMAC™ F1 acoustic logging service with the deep shear wave imaging (DSWI) processing service, and cuttings analysis. Identification of the high-stress zones, natural fractures, and like-type rock enabled the operator to optimally place the fracture stages and perforation clusters. Accurate prediction of
reserves despite reduced lateral length
nnMitigate
high screenout risks
nnManage
high-stress zones requiring high fracturing treatment pressures
nnEffectively
fracture despite high downhole pressure
Baker Hughes solution nnFracFit
fracturing optimization solution –– XMAC F1 acoustic logging service –– DSWI processing service –– Cuttings analysis
CASE HISTORY the lateral’s high pressure zones let the operator avoid screenouts while achieving a better fracture with more uniform distribution of the fracturing fluid and proppant.
During the first two weeks of production, the optimized well was producing 44% more oil per lateral foot. This allowed the operator to improve its production over its offset well, which had a lateral that was approximately 2,000 ft (609 m) longer.
Production from the exploratory program indicated there were sufficient reserves to justify financing for the larger multi-well development program.
Identified similar stress zones with ~2,000 psi variance in the same lateral XMAC F1 service with DSWI processing identified formation features up to 100 ft away from the wellbore
Identified naturally fractured areas and like-type rock for optimal cluster placement
Cuttings analysis provided mineralogy, lithology, and rock brittleness information
The FracFit solution helped the operator identify the high-stress zones, natural fractures, and like-type rock for optimal placement of the fracture stages and perforation clusters.
Disclaimer of Liability: This information is provided for general information purposes only and is believed to be accurate as of the date hereof; however, Baker Hughes Incorporated and its affiliates do not make any warranties or representations of any kind regarding the information and disclaim all express and implied warranties or representations to the fullest extent permissible by law, including those of merchantability, fitness for a particular purpose or use, title, non-infringement, accuracy, correctness or completeness of the information provided herein. All information is furnished “as is” and without any license to distribute. The user agrees to assume all liabilities related to the use of or reliance on such information. BAKER HUGHES INCORPORATED AND ITS AFFILIATES SHALL NOT BE LIABLE FOR ANY DIRECT, INDIRECT, SPECIAL, PUNITIVE, EXEMPLARY OR CONSEQUENTIAL DAMAGES FROM ANY CAUSE WHATSOEVER INCLUDING BUT NOT LIMITED TO ITS NEGLIGENCE.
© 2016 Baker Hughes Incorporated. All rights reserved. 43690 02/2016
