Estimating Formation Properties in Heterogeneous Reservoirs Using 3D Interval Pressure Transient Test and Geostatistical Data (2005)

Estimating Formation Properties in Heterogeneous Reservoirs Using 3D Interval Pressure Transient Test and Geostatistical Data Ihsan Gok; Ihsan Gok Schlumberger Search for other works by this author on: This Site Google Scholar Mustafa Onur; Mustafa Onur Istanbul Technical U. Search for other works by this author on: This Site Google Scholar Fikri J. Kuchuk Fikri J. Kuchuk Schlumberger Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Middle East Oil and Gas Show and Conference, Kingdom of Bahrain, March 2005. Paper Number: SPE-93672-MS https://doi.org/10.2118/93672-MS Published: March 12 2005 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Gok, Ihsan, Onur, Mustafa, and Fikri J. Kuchuk. "Estimating Formation Properties in Heterogeneous Reservoirs Using 3D Interval Pressure Transient Test and Geostatistical Data." Paper presented at the SPE Middle East Oil and Gas Show and Conference, Kingdom of Bahrain, March 2005. doi: https://doi.org/10.2118/93672-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Middle East Oil and Gas Show and Conference Search Advanced Search ProposalThe medium scale formation heterogeneity (about 1 foot to 100 feet near-wellbore) cannot be usually resolved well by conventional well test data, particularly in vertical direction. Spatial pressure data sets from the interval pressure transient testing (IPTT) along the wellbore measured by using multi-probe and dual packer-probe wireline formation testers (WFT) provide information about near-wellbore heterogeneity. The objective of this work is to examine the use of spatial 3D (three dimensional) IPTT data acquired by dual packer-probe WFTs and geostatistical information for estimating heterogeneous formation properties (e.g. horizontal and vertical permeability) in both lateral and vertical directions along the wellbore. There has been no systematic study in the literature about resolving heterogeneity in horizontal and vertical permeability and porosity from spatial 3D IPTT data. Throughout, formation property and parameter will be used interchangeably.In this study, a 3D single-phase single-well (r-T-z) numerical flow model (simulator) was developed to simulate the behavior of IPTT measurements in heterogeneous media. Heterogeneity in formation properties is modeled at the gridblock scale by using geostatistics that allows properties to be treated as random regional variables with certain correlation structures. Horizontal and vertical property distributions conditional to IPTT data sets are estimated by using the inverse problem methodology based on Bayesian probability theorem. For estimation of formation parameters (properties) conditional to IPTT spatial data sets and geostatistical model, we minimize the objective function resulting from the application of the Bayesian probability theorem by using the well-known Levenberg-Marquardt (LM) algorithm. The sensitivity coefficients required in the LM algorithm are efficiently computed by using the adjoint method. We also show maps of sensitivity coefficients of packer interval and observation probe pressures with respect to parameter distributions (e.g., horizontal/vertical permeabilities and porosities) that offer important evidence about near-wellbore heterogeneities, where formation property distributions might be well resolved by interval pressure transient data.Synthetic examples are presented to show the methodology proposed in this work.IntroductionAs stated well by Weber[1]: "Reservoir heterogeneity is among the major reasons why enhanced oil recovery is so difficult. Projects undertaken without detail reservoir evaluation often end in failures related to unexpected baffles to flow, permeability heterogeneity, ..." This is predominantly true for carbonate formations where reservoir heterogeneity exists at many different scales. Therefore, characterization of formation parameter distributions is essential for many oilfield activities such as performance predictions and enhanced oil recovery.Although our methodology presented can be applied to any scale as well as incorporating conventional and extended well test pressure data like DSTs, in this work, we mainly focus on estimating formation parameters in heterogeneous reservoirs at the small and medium scales by using IPTT data. The core and well log scales are normally small. The medium scale is about 1 foot to 100 feet in the near-wellbore region. It is well known that particularly medium-scale heterogeneities are much more difficult to evaluate from core and well log data as well as from seismic data. For instance, stylolite zones, which may alter vertical permeability drastically, in carbonate formations may not be easily characterized from core, well log, and seismic data. Keywords: boundary, sensitivity coefficient, artificial intelligence, pressure transient testing, drillstem/well testing, probe pressure, coefficient, pressure transient analysis, gridblock, variance Subjects: Formation Evaluation & Management, Pressure transient analysis, Drillstem/well testing This content is only available via PDF. 2005. Society of Petroleum Engineers You can access this article if you purchase or spend a download.