Description
One of our industry’s challenges is an accurate assessment of reserves and a predictive understanding of reservoir performance once a deepwater exploration well comes on line. Early prognostication of key reservoir metrics give reservoir engineers the opportunity to make proactive and knowledgeable drilling, development and production decisions. Additionally, the booking of reserves earlier, with more precision and less risk, is a key economic advantage.
The authors, a team representing Shell Exploration and Production Company, Kerr-McGee Corporation, Ocean Energy, Inc., and Object Reservoir, Inc., employed a new technology and process called Dynamic Reservoir Characterization™ to model wells #6 and #7 from the East Boomvang Field, East Breaks 688. Areas investigated included reserves determination, production forecasts, drive mechanism, reservoir shape and flow barriers. Using the first four months of production and pressure data, as well as Kerr McGee’s seismic and geologic interpretation, the team sought to answer the following questions:
a) What were the reserves and how could they be proved up with the model?
b) How much gas could be recovered from the two wells?
c) Was the fault to the north of well #6 leaky and did it communicate with fault block E to the north?
d) Was the fault between wells #6 and #7 an isolating fault?
e) When would water be produced by the two wells? How much water? When would the wells water out?
The team was able to investigate four different models of the subsurface, using Object Reservoir’s Resolve™ technology. It uses finite element modeling of fluid flow and automated, unstructured meshing to represent geology. All of these models were able to represent the fault boundaries cleanly and accurately (not in stair step fashion as seen with conventional finite difference technology). The models investigated included:
a) Model of communication across the fault to the north of well #6
b) Lower permeability model in and around well #6;
c) Isolation of the two wells with two separate reservoirs and one aquifer;
d) Limited communication between the two gas reservoirs.
As a result of the investigations above, the team was able to accurately size reserves and forecast with precision both the gas and water production profiles. The team found there is no communication with fault block E via the fault north of well #6. It was also determined that there is limited communication between wells #6 and #7. In summary, the team found the following:
a) OGIP is 71.4 BCF
b) 64 BCF will be recovered up to day 2539
c) #6 begins producing water at day 430
d) #6 reaches 2500 stb/day at day 528
e) #7 begins producing water at day 1589 and never exceeds 1000 bbl/day
f) #7 gas production drops below 1MMscf./day at day 2539
g) Aquifer support is not observed until 25-30 days into production.
One of the primary results of this project was the ability to book more reserves as proved. Another benefit of this technology and service is the rapidity with which the work can be completed, the number of scenarios that can be investigated, and the oppo
The authors, a team representing Shell Exploration and Production Company, Kerr-McGee Corporation, Ocean Energy, Inc., and Object Reservoir, Inc., employed a new technology and process called Dynamic Reservoir Characterization™ to model wells #6 and #7 from the East Boomvang Field, East Breaks 688. Areas investigated included reserves determination, production forecasts, drive mechanism, reservoir shape and flow barriers. Using the first four months of production and pressure data, as well as Kerr McGee’s seismic and geologic interpretation, the team sought to answer the following questions:
a) What were the reserves and how could they be proved up with the model?
b) How much gas could be recovered from the two wells?
c) Was the fault to the north of well #6 leaky and did it communicate with fault block E to the north?
d) Was the fault between wells #6 and #7 an isolating fault?
e) When would water be produced by the two wells? How much water? When would the wells water out?
The team was able to investigate four different models of the subsurface, using Object Reservoir’s Resolve™ technology. It uses finite element modeling of fluid flow and automated, unstructured meshing to represent geology. All of these models were able to represent the fault boundaries cleanly and accurately (not in stair step fashion as seen with conventional finite difference technology). The models investigated included:
a) Model of communication across the fault to the north of well #6
b) Lower permeability model in and around well #6;
c) Isolation of the two wells with two separate reservoirs and one aquifer;
d) Limited communication between the two gas reservoirs.
As a result of the investigations above, the team was able to accurately size reserves and forecast with precision both the gas and water production profiles. The team found there is no communication with fault block E via the fault north of well #6. It was also determined that there is limited communication between wells #6 and #7. In summary, the team found the following:
a) OGIP is 71.4 BCF
b) 64 BCF will be recovered up to day 2539
c) #6 begins producing water at day 430
d) #6 reaches 2500 stb/day at day 528
e) #7 begins producing water at day 1589 and never exceeds 1000 bbl/day
f) #7 gas production drops below 1MMscf./day at day 2539
g) Aquifer support is not observed until 25-30 days into production.
One of the primary results of this project was the ability to book more reserves as proved. Another benefit of this technology and service is the rapidity with which the work can be completed, the number of scenarios that can be investigated, and the oppo