|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
New reservoir characterization methods are needed to integrate multiscale exploration and development data, particularly at the interface between well and field models. In this paper, we illustrate a novel workflow involving high-resolution near-wellbore modeling (NWM), which allows us to accurately include seismic, wireline data, image logs, and well core logs from highly heterogeneous reservoirs in field-scale reservoir simulations. We demonstrate that an NWM-enhanced geoengineering workflow has the potential to improve reservoir characterization by applying it to a realistic clastic reservoir with high variance at small scale. We have performed a number of sensitivities comparing conventional local grid refinement (LGR) in the near-wellbore region with that involving NWM, and we obtained a significant increase in the accuracy of reservoir characterization and the calibration of dynamic models. Centimeter-scale models, containing several million cells, representing the fine geological details of the nearwellbore region, were constructed with available data from core and openhole well-log suits. The resulting well models were upscaled into regular grids with the highest resolution possible through the NWM software and incorporated into a field-scale simulation model to evaluate the dynamic behavior of the reservoir with a static-model transient test. Our results show that the use of NWM tools for reservoir modeling yields more precise flow calculations and improves our fundamental understanding of the interactions between the reservoir and the wellbore.
Home About Committees What's New Attend Schedule Speakers Training Courses Energy Education Programmes Student Education Programmes Teacher Education Programmes Young Members Activities Justification Toolkit SPE Cares Travel and Accommodation Visa Information Local Transportation Shuttle Bus Schedule Tours Registration Exhibit Why Participate Become an Exhibitor Find an Exhibitor Manage Your Exhibit (Exhibitor Service Manual) Rebook for 2017 Sponsor and Advertise Sponsor Profiles Premium and Standard Packages Special Packages PetroBowl Sponsorships NE Section Golf Day Advertise Media Media Information Media Supporters Media Registration Schedule Session Details Expand All Collapse All Filter By Date All Dates Saturday, September 24 Sunday, September 25 Monday, September 26 Tuesday, September 27 Wednesday, September 28 Thursday, September 29 Filter By Session Type All Sessions General Activities Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions ...
Saudi Aramco is actively appraising the numerous unconventional shale and tight sand opportunities located across the kingdom of Saudi Arabia. The early phase of the unconventional gas program in the company has been directed towards exploration data gathering activities through drilling, coring, open-hole logging and completion of shale and tight sand gas resources. Due to the ultra-tight nature of these reservoirs, several vertical and horizontal wells have been drilled and completed with multistage hydraulic fractures to be able to produce them. Initial flow back tests, in addition to long term pressure build-up, have already been conducted on some of these wells, the analysis of which will help to characterize and better understand these tight hydrocarbon reservoirs.
This paper discusses the results of pressure transient analyses and modelling performance of two unconventional tight sand wells. An Integrated workflow was developed for reservoir characterization and fluid flow modeling using well test analyses and a simulation tool designed specifically for unconventional reservoirs. Post fracture flowback data along with available petrophysical interpretation, geological and geophysical analyses and 3-D hydraulic fracture models were used to build and calibrate single well numerical models. For the purpose of comparison, two wells were selected: one from a dry gas reservoir, while the other was from a rich gas-condensate reservoir.
Aftab, Muhammad (ADNOC Onshore) | Talib, Noor (ADNOC Onshore) | Subaihi, Maad (ADNOC Onshore) | Lazreq, Nabila (ADNOC) | Nechakh, Abderaouf (Halliburton Energy Services OK) | Leguizamon, Javier (Halliburton Energy Services OK) | Dunlop, Tyson (Halliburton Energy Services OK)
Successful completion and performance of a horizontal well is one of the most dynamic and complex tasks within the oilfield industry, especially when conventional well is an underperformer.
Sustaining production from tight reservoirs with conventional stimulation techniques is one of the most challenging tasks. The reservoir of interest is a tight, low permeable carbonate with thin layers. Productivity proven insignificant with considerable in place volume. The objective is to increase and sustain productivity of a pilot well that consists of an open-hole completion.
Multi-disciplinary data is reviewed in a systematic way to identify reasons of low productivity and to identify possible solutions. After comprehensive studies and risk assessments, it is concluded to re-complete well with cemented Frac string to perform hydraulic fracturing with Plug and Perf (PnP) technique. This technique is applied within a conventional tight reservoir, allowing for the flexibility of stage count, stage spacing, and multi-cluster design in order to maximize the stimulated reservoir volume (SRV) along 2,000 ft. in upper layer, 1,000 ft. across middle layers and 2,000 ft. in lower layer. In addition, company and service provider collaborated to enhance this design through a zero over-flush technique along with diverting agents.
Core, logging data collected from pilot hole is used to build 1D Mechanical Earth Model (MEM), which is further calibrated with MiniFrac performed with Wireline Formation Tester (WFT).
A challenge is to avoid Frac height growth towards underlying reservoir, which is separated by dense carbonate layer of 40 ft.
Extensive modeling is conducted in order to choose correct Frac design along the lateral in which landing depth is variable in different target layers of interest that added complexities to Frac Fluid selection. Finally, two Frac systems are selected for different segments of the lateral. After running a cemented casing, Six (06) Acid fracturing treatment and five (05) Proppant fracturing treatments are successfully executed in the lower and upper layers respectively.
A comprehensive production test is performed to evaluate and compare the testing results of pre and post frac well. To evaluate the contribution of each stage, a Production Logging Tool (PLT) is deployed. The PLT tool shows the contribution and flow distribution across all the clusters and the efficiency of the Frac design and diversion technique/system.
This paper summarizes the design processes, selection criteria, challenges, and lessons learned during design and execution phases. It may provide a potential approach for selecting the proper hydraulic fracturing (Acid Vs Prop) and technique (PnP with clusters Vs PnP with one set of perforation). Company has significant portfolio of undeveloped tight carbonate reservoirs with low productivity and considerable volume in place. This technique will pave the way for developing these reservoirs.
Figure 1—BHP, bottomhole-temperature (BHT), and WHP data gathered during a falloff test. Diagnostic fracture injection tests (DFITs) have gained widespread usage in the evaluation of unconventional reservoirs. In typical field operations, pressure is measured at the wellhead, not at the bottom of the hole. The bottomhole pressure (BHP) is obtained by adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. One can question the soundness of this practice because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column.