Dommisse, Robin (University of Texas) | Janson, Xavier (University of Texas) | Male, Frank (University of Texas) | Price, Buddy (The University of Texas at Austin) | Payne, Simon (Ikon Science) | Lewis, Andrew (Fairfield Geotechnologies)
Modern reservoir characterization approaches can be greatly aided by incorporating all available data and interpretations in a three dimensional geomodel. Our goal is to offer a regional perspective to augment the interpretations from local, field-scale 3D models developed by the industry. In this work we highlight the benefits of continuous development of the geomodel for the characterization of the facies architecture of an unconventional play.We generated a three dimensional, faulted Delaware Basin geomodel, containing over 1 billion cells, including stratigraphic, petrophysical, core description, and production data for the Bone Spring and Wolfcamp intervals. The model is based on over 7,000 correlated wells, 650 wells with facies interpretations and approximately 9,000 horizontal production wells with analyzed decline curves and completion data. Additionally, a high-quality 3D seismic volume in the northeastern part of the Delaware Basin reveals the complex stratigraphic architecture of key producing intervals in the Permian Basin. The 3D volume, combined with regional 2D seismic lines, enabled refining the interpretation of the stratigraphic architecture of the Wolfcampian to Guadalupian shelf margin. This allows us to relate the slope to basin strata imaged in the 3D seismic to the well-established stratigraphic architecture of the surrounding platforms. The 3D seismic volume reveals the seismic geomorphology of several key intervals. There are two areas of focus: 1) Testing of the facies model derived from log and core analyses using different deterministic and stochastic attribute distribution techniques; and 2) Exploring the influence of geological trends on productivity. This work demonstrates the value of a multiscale, regional perspective to the practice of 3D reservoir characterization in the Delaware Basin.
Alimahomed, Farhan (Schlumberger) | Haddad, Elia (Schlumberger) | Velez, Edgar (Schlumberger) | Foster, Randy (Triumph Exploration) | Downing, Terrell (Triumph Exploration) | Seth, Cody (Triumph Exploration) | Melzer, Steve (Melzer Consulting) | Downing, Will (Melzer Consulting)
The San Andres is one of the most prolific conventional carbonate plays in the Permian Basin. It primarily occurs in the Central Basin Platform, but some fields are spread throughout the Northwest Shelf. The variation of the log profiles across the platform indicates a staged history and, challenging geological setting, which can have an impact on the lateral variability, landing zones and the completion techniques. Horizontal wells being a relatively new way to exploit this play, there are several challenges associated with making it economic. These challenges were faced in a program involving three horizontal wells on the Central Basin Platform. High tier petrophysical and sonic logs in the pilot, sonic and image logs in the lateral, and real-time microseismic data, were analyzed in the program.
Integrating data from various disciplines such as geology, petrophysics, geomechanics, completion engineering and reservoir engineering plays a significant role in identifying trends and key drivers of production. In the San Andres three-well program, high-tier petrophysical and sonic logging data were collected in the vertical pilot well. A fracture injection test (FIT) was performed to calibrate the rock properties. A 3D geomodel was built around the area of interest using well tops from offset vertical wells, and was refined to a localized structure around individual wellbores using dips from lateral image logs. Fracture simulations were performed to determine the optimum job size to cover the pay zone. Image logs in the lateral were interpreted for fractures and bedding planes, and to understand the changes in rock facies along the length of the lateral. Open hole sonic measurements in the lateral were used to place perforations in similar type of rock based on good reservoir quality and completion quality. Laboratory tests were performed on oil samples to determine the oil properties. Cuttings were analyzed to determine their solubility with acid. Two horizontal wells were monitored using real-time downhole microseismic. Post job analysis was performed to tie all the observations together.
Analysis of the injection test indicated slightly lower than normal reservoir pressure. Pilot-hole logs indicated a variable zone with mobile oil (pay) which was overlain on the top by anhydrite stringers and beds; higher water saturations were observed below the zone. The three horizontal wells in this program were all landed at various depths from the mobile oil interval to understand the impact on production. Step down tests were performed and analyzed on several stages to quantify near-wellbore friction pressures. Microseismic data showed planar features in stages that had fewer fractures identified on the image logs. High treating pressures were observed on alternate stages indicating some degree of stress shadow. Image logs in the laterals showed features such as anhydrite nodules and distinct layering of the rock, which can have a significant impact on the hydraulic fracture growth and also on production. The analysis of the fracture treatment and microseismic data yielded important information, and the program included the adoption of appropriate technologies and formulation of workflows for effective analysis.
The San Andres wells have been cost effective to drill and complete throughout the oil price downturn, but there are still many questions to be answered to make it an extremely successful play. The results and observations from this three-well program provide insights that will assist in planning and designing future projects.
Organic-rich mudrocks (ORM) from the Brushy Canyon Formation in west Texas were deposited in the Middle Permian during the Guadalupian epoch in the Delaware Basin. Brushy Canyon ORM were examined for Re-Os isotope systematics with a goal of constraining their depositional age, the 187Os/188Os value of seawater at their time of deposition, and to examine how Re and Os partition into organic material in ORM. For these samples, Rock-Eval pyrolysis data (HI: 228-393 mg/g; OI: 16-51 mg/g) indicates predominantly Type II marine kerogen with minor contributions of Type III terrestrial organic matter. Rhenium and osmium abundances correlate positively with HI, and negatively with OI, which are proxies for organic matter type and degree of preservation. These data are consistent with previous work that indicates Re and Os abundances are controlled by the availability of chelating sites in the kerogen. Brushy Canyon Formation samples have (total organic carbon) TOC values between 0.97 and 4.04% and show a strong positive correlation with both Re and Os abundances, consistent with correlations between these parameters in other ORM suites. The positive slopes in these correlations are distinct between marine (higher slopes) and non-marine (lower slopes) lacustrine environments of deposition. The Brushy Canyon’s steep slopes are consistent with marine deposition of its organic matter and an open-ocean non-restricted setting. The relationship to other Re-Os and TOC data sets appears to be a function of the restrictivity of marine conditions, and associated variations in reducing conditions during ORM accumulation of the Delaware Basin compared with more restricted lacustrine basins with local drawdown of Re and Os.
The Re-Os isotope systematics of ORM from the Brushy Canyon Formation yields a Model 1 age of 261.3 ± 5.3 Ma (2.0% age uncertainty; MSWD = 0.82). Within the uncertainty, this agrees with the expected Guadalupian age for this formation. This Re-Os age represents the first direct, absolute age for Guadalupian organic matter in the Delaware Basin. The initial (187Os/188Os)i = 0.50 ± 0.06 obtained by isochron regression represents the 187Os/188Os of seawater at this time. This value is significantly less radiogenic than modern day seawater (~1.06). The lower 187Os/188Os of Guadalupian seawater recorded is likely caused by a decrease in the relative flux of radiogenic Os from continental weathering due to a number of local and global climatic and tectonic changes that were occurring during this time.
Zhang, Jie (PetroChina Hangzhou Research Institute of Geology, CNPC Key Laboratory of Carbonate Reservoir) | Zhu, Guohua (PetroChina Hangzhou Research Institute of Geology) | Yao, Genshun (PetroChina Hangzhou Research Institute of Geology) | Li, Yuwen (PetroChina Hangzhou Research Institute of Geology) | Wang, Xin (PetroChina Hangzhou Research Institute of Geology) | Yu, Chaofeng (PetroChina Hangzhou Research Institute of Geology)
In the Junggar Basin, Tuha Basin, and Santanghu Basin of North Xinjiang, high oil production comes from the Middle Permian Lucaogou Formation (Figure 1). The oil-producing zone in the Lucaogou Formation in the Malang Sag of the Santanghu Basin is the hydrocarbon source rock, which has 1.38~11.90% TOC and 0.01-22.20m3/d oil production (Liang et al., 2012). The sediments that nor form the Middle Permian Lucaogou Formation of this area developed in extensive lacustrine systems. Permian is the early stage of the formation of Junggar Basin, which is the transitional period from geosyncline to platform. In the lacustrine environments affected by volcanic dusts in other Basins in North Xinjiang, there would be this typical source rock.