Fractures can be first-order controls on fluid flow in hydrocarbon reservoirs. Understanding the characteristics of fractures such as their aperture, density, distribution, conductivity, connectivity, etc, is key for reservoir engineering and production analysis.
Well testing plays a key role in the the characterisation of fractured reservoirs, especially. New advances in the Pressure Transient Analysis (PTA) have enabled the interpretation of production data in a way where the resulting geological scenarios are in better agreement with fracture patterns observed in outcrop analogues.
Traditionally, Drill Stem Test (DST) data have been the primay source of information for well testing. However, we hypothesise that wireline conveyed tools designed for Interval Pressure Transient Testing (IPTT) could yield a more throrough description of the near-wellbore heterogeneities, including fractures.
Hence, we investigate the applicability of IPTT for characterising fractured reservoirs using detailed numerical simulations models with accurate wellbore representation to generate synthetic IPTT responses that can obtained through a next-generation wireline testing tool called SATURN. We particularly focus on cases where fractures are present in the near-wellbore region but do not intersect the wellbore. The study included parameters such as fracture densities and conductivities, distance between fractures and wellbore and the vertical extension of the fractures across geological beds.
The impact of the different fracture scenarios on the pressure transient tests was recorded as characteristic signatures on diagnostic plots (pressure derivative curves). We have called these curves "IPTT-Geotypes"; they can be used to assist the interpretation process of IPTT responses. To the best of our knowledge, this is the first time pressure derivative type curves for IPTT in fractured reservoirs are presented in the literature.
A field example of an IPTT case was analysed using the concept of geological well testing. We integrated the information from petrophysical logs and the IPTT-Geotypes to assist the calibration of a reservoir model developed to represent the geological setting of the tested reservoir interval. The results provided a sound interpretation of the reservoir geology and quantitative estimation of the matrix and fracture parameters.
The SWP project is located in a mature waterflood undergoing conversion to CO2-WAG operations at Farnsworth, Texas, USA. Utilized CO2 is anthropogenic, sourced from a fertilizer and an ethanol plant. Major project goals are optimizing the storage/production balance, ensuring storage permanence, and developing best practices for CCUS.
This paper provides a review of work performed toward development of a 3D coupled Mechanical Earth Model (MEM) for use in assessment of caprock integrity, fault reactivation potential, and evaluation of stress dependent permeability in reservoir forecasting. Mechanical property estimates computed from geophysical logs at selected wellbores were integrated with 3D seismic elastic inversion products to create a 3D "static" mechanical property model sharing the same geological framework as the existing reservoir simulation model including 3 major faults. Stresses in the MEM were initialized from wellbore stress estimates and reservoir simulation pore pressures. One way and two way coupled simulations were performed using a compositional hydrodynamic flow model and geomechanical solvers.
Coupled simulations were performed on history matched primary, secondary (waterflood), and tertiary (CO2 WAG) recovery periods, as well as an optimized WAG prediction period. These simulations suggest that the field has been operating at conditions which are not conducive to either caprock failure or fault reactivation. Two way coupled simulations were performed in which permeability was periodically updated as a function of volumetric strain using the Kozeny-Carmen porosity-permeability relationship. These simulations illustrate the importance of frequent permeability updating when recovery scenarios result in large pressure changes such as in field re-pressurization through waterflood after a long primary depletion recovery period. Conversely, production forecasting results are less sensitive to permeability update frequency when pressure cycles are short and shallow as in WAG cycles.
This paper describes initial work on development of a mechanical earth model for use in assessment of geomechanical risks associated with CCUS operations at FWU. The emphasis of this work is on integration of available geomechanical data for creation of the static mechanical property model. Preliminary coupled hydro-mechanical simulations are presented to illustrate some of the key diagnostic output from coupled simulations which will be used in later work for in depth evaluation of specific risk factors such as induced seismicity and caprock integrity.
The reporting of potential resources is essential to assess the future development plan and profitability of a petroleum discovery, but if the project is under appraised and production data are absent, analysts often use analogs for preliminary estimates of technically recoverable volumes. To address this, a workflow is presented for selecting appropriate analogs for unconventional plays and using them to estimate the target play's potential. The proposed technique is demonstrated with a case study of the as-yet undeveloped Bowland Shale, which is the most prominent of the shale plays in the United Kingdom (UK) and is at the early stage of its assessment. The paper describes the current shale gas activity in the UK, highlighting the enviromental constraints placed on would-be Bowland Shale developers, which impact on drilling and production operations and stem from the geographic proximity of urban developments, infrastructure and nature, which limit the size of well pad footprint in the UK where land use is high. Studies have estimated the play's in-place resources for possible future development, but there are few estimates of its corresponding recoverable volumes due to lack of production history. At the outset, a database is created with published minimum-average-maximum ranges of key parameters such as total organic carbon, maturity level, gas filled porosity, permeability, etc. that play a major role in resources estimation and recovery potential for all unconventional plays. A comparison of triangular distributions, key parameter by key parameter, between the target shale play and the analog database, is then carried out using novel graphical and statistical methods to establish a "confidence factor" relating to the analog's viability. The most appropriate analog for the Bowland Shale is chosen from an exhaustive list of North American shale gas plays. Analytical approaches are then used to transform a model of the published type well performance of the selected analog by exchanging key model parameters with those of the target shale play. The paper shows how UK operational constraints can be statistically incorporated into the workflow and have a marked effect on the estimated recovery from the Bowland Shale.
The aim of this paper is to compare the performance of three horizontal infill wells in a mature field, of which one is completed with autonomous inflow control devices (AICDs). The analytic results are based on the comparison of oil production rates; water cut development and water-oil ratio plots of the wells. All the wells in this study are producing from the same homogeneous sandstone reservoir.
Two of the horizontal infill wells are targeting attic oil in an area with low risk of gas production of which one of these wells is completed with slotted liners and the other with AICDs. Both are artificially lifted with high rate electrical submersible pumps (ESPs). The third horizontal well was placed in an area with higher gas saturation, where a completion with casing, cementation and perforation was used. The performance of the horizontal wells is compared against each other.
The use of active geo-steering successfully supported the well placement into the "sweet spot" of the reservoir due to real-time well path adjustments.
It was found that the AICDs choke back a high amount of fluid and keep the water cut at a stable plateau level. This observation underlines the key benefit of using AICDs as when comparing to the other producing wells without AICDs, the water cut is steadily increasing.
Therefore the use of AICDs is a real option for horizontal well completion.
This paper will be useful to those who are in a phase of early well planning, e.g. in a field (re-)development project and have to select the best well concept (e.g. slotted liner vs. AICDs). AICDs have proven their value even in a super-mature oil field by improving production. Further advantages and challenges during operation are discussed in this paper.
Analytically-derived criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. The criteria are developed considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of longitudinal fractures and another for the initiation of transverse fractures, with respect to the wellbore. In-situ stress state, wellbore pressure, and the formation's mechanical and poroelastic properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
The DITF orientation can be used to constrain the magnitude of the maximum horizontal stress; the most difficult aspect of the in-situ stress tensor to constrain. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. However, transverse CIHF initiation occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted is shown in dimensionless plots for perforated and non-perforated wellbores. Fracture initiation criteria for specific cases presented can be used to predict the orientation of fracture initiation in oilfield operations.
The orientation of CIHFs controls the productivity of hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Fracture initiation often follows a plane different to the final fracture propagation plane. Stress re-orientation in the near-wellbore region may promote fracture initiation of different orientation than the orientation dictated by the far-field stresses. The range of in-situ stress states in which transverse fracture initiation is promoted increases as Biot's poroelastic coefficient,
You, Junyu (Petoleum Recovery Research Center) | Ampomah, William (Petoleum Recovery Research Center) | Kutsienyo, Eusebius Junior (Petoleum Recovery Research Center) | Sun, Qian (Petoleum Recovery Research Center) | Balch, Robert Scott (Petoleum Recovery Research Center) | Aggrey, Wilberforce Nkrumah (KNUST) | Cather, Martha (Petoleum Recovery Research Center)
This paper presents an optimization methodology on field-scale numerical compositional simulations of CO2 storage and production performance in the Pennsylvanian Upper Morrow sandstone reservoir in the Farnsworth Unit (FWU), Ochiltree County, Texas. This work develops an improved framework that combines hybridized machine learning algorithms for reduced order modeling and optimization techniques to co-optimize field performance and CO2 storage.
The model's framework incorporates geological, geophysical, and engineering data. We calibrated the model with the performance history of an active CO2 flood data to attain a successful history matched model. Uncertain parameters such as reservoir rock properties and relative permeability exponents were adjusted to incorporate potential changes in wettability in our history matched model.
To optimize the objective function which incorporates parameters such as oil recovery factor, CO2 storage and net present value, a proxy model was generated with hybridized multi-layer and radial basis function (RBF) Neural Network methods. To obtain a reliable and robust proxy, the proxy underwent a series of training and calibration runs, an iterative process, until the proxy model reached the specified validation criteria. Once an accepted proxy was realized, hybrid evolutionary and machine learning optimization algorithms were utilized to attain an optimum solution for pre-defined objective function. The uncertain variables and/or control variables used for the optimization study included, gas oil ratio, water alternating gas (WAG) cycle, production rates, bottom hole pressure of producers and injectors. CO2 purchased volume, and recycled gas volume in addition to placement of new infill wells were also considered in the modelling process.
The results from the sensitivity analysis reflect impacts of the control variables on the optimum results. The predictive study suggests that it is possible to develop a robust machine learning optimization algorithm that is reliable for optimizing a developmental strategy to maximize both oil production and storage of CO2 in aqueous-gaseous-mineral phases within the FWU.
Kutsienyo, Eusebius Junior (Petroleum Recovery Research Center) | Ampomah, William (Petroleum Recovery Research Center) | Sun, Qian (Petroleum Recovery Research Center) | Balch, Robert Scott (Petroleum Recovery Research Center) | You, Junyu (Petroleum Recovery Research Center) | Aggrey, Wilberforce Nkrumah (KNUST) | Cather, Martha (Petroleum Recovery Research Center)
This paper presents field-scale numerical simulations of CO2 injection activities in the Pennsylvanian Upper Morrow sandstone reservoir, usually termed the Morrow B sandstone, in the Farnsworth Unit (FWU) of Ochiltree County, Texas. The CO2 sequestration mechanisms examined in the study include structural-stratigraphic, residual, solubility and mineral trapping. The reactive transport modelling incorporated in the study evaluates the field's potential for long-term CO2 sequestration and predicts the CO2 injection effects on the Morrow B pore fluid composition, mineralogy, porosity, and permeability.
The dynamic CO2 sequestration model was built from an upscaled geocellular model for the Morrow B. This model incorporated geological, geophysical, and engineering data including well logs, core, 3D surface seismic and fluid analysis. We calibrated the model with active CO2-WAG miscible flood data by adjusting control parameters such as reservoir rock properties and Corey exponents to incorporate potential changes in wettability. The history-matched model was then used to evaluate the feasibility and mechanisms for CO2 sequestration. We used the maximum residual phase saturations to estimate the effect of gas trapped due to hysteresis. The coupled approach which involves the aqueous phase solubility and geochemical reactions were modelled prior to import into the compositional simulation model. The viscosities of the liquid-vapor phases were modeled based on the Jossi-Stiel-Thodos Correlation. This correlation depended on the mixture density calculated by the equation of state. The gas solubility coefficients for the aqueous phase were estimated using Henry's law for various components as function of pressure, temperature, and salinity. The characteristic intra-aqueous and mineral dissolution/precipitation reactions were assimilated numerically as chemical equilibrium and rate-dependent reactions respectively. Multiple scenarios were performed to evaluate the effects and potentials of the CO2 sequestrated within the Morrow formation. Additional scenarios that involve shut-in of wells were performed and the reservoir monitored for over 150 years to understand possible dissolution/precipitation of minerals. Changes in permeability as a function of changes in porosity caused by mineral precipitation/dissolution were calibrated to the laboratory chemo-mechanical responses.
This confirms the CO2 injection in the morrow B will alter petrophysical properties, such as permeability and porosity in short-term due to the dissolution of calcite. However, further investigation for the long-term effects needs to be conducted. Moreover, the following significant observations are extracted from the result of this study: oil recovery, total volume of CO2 due to multiple trapping mechanisms, effect of salinity, the timescale-view of the dissolution/precipitation evolution in the Morrow B sandstone.
Experiences gained from this study offers valuable visions regarding physiochemical storage induced by the CO2 injection activities and may serve as a benchmark case for future CO2-EOR projects when reactive transportations are considered.
Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Alashwak, Nawaf A. (Missouri University of Science and Technology) | Alshammari, Abdullah F. (Missouri University of Science and Technology) | Alkhamis, Mohammed M. (Missouri University of Science and Technology) | Mutar, Rusul A. (Ministry of Communications and Technology)
Drilling wastes generated in large volumes is recognized to have many effects on the environment. Several techniques have been applied by the oil and gas industry to overcome the impacts of drilling waste on the environment, an example of these techniques is using environmental friendly drilling fluid additives.
This work investigates the potential of using White Sunflower Seeds’ Shell Powder (WSSSP) as an environmental friendly drilling fluid additive. This material was prepared in-house. Experimental evaluation has been carried out to investigate the ability of WSSSP to enhance several properties of water-based drilling fluid under two different pH conditions. The WSSSP was first evaluated at 9.3 pH then the pH was increased using sodium hydroxide to 11.5. Several properties of drilling fluid were measured. The measurements included testing the rheological properties using viscometer, measuring the filtration using standard low-pressure low-temperature filter press, the pH using pH tester, and other important properties.
The findings of this work showed that WSSSP in 9.3 pH environment reduced the fluid loss by 18% and 30% when 1% and 2% concentrations of WSSSP were added, respectively. This reduction in fluid loss was along with forming a thin filter cake. The filter cake thickness of the reference fluid was decreased from 3 mm to 2.14 mm and 1.9 mm at 1% and 2% concentrations of WSSSP. Additionally, WSSSP resulted in increasing the plastic viscosity (PV) compared to the reference fluid by 33.33% at 1% and 2% concentrations. While the yield point (YP) was increased by 22.22% and 44.44% when 1% and 2% concentrations of WSSSP were added, respectively. Both the initial and final gel strengths were increased by 27.27%, 44.44 %, 7.14% and 14.28% at 1% and 2% concentrations, respectively. Moreover, the results in 11.5 pH emphasized the efficient performance of WSSSP, and it showed better improvement in the filtration specifications and the rheological properties. In other words, PV, YP, and gel strength were significantly increased; while the fluid loss was very low and the filter cake was very thin at 11.5 pH condition compared to 9.3 pH condition for the same concentrations, proving the ability of WSSSP to perform better under higher pH condition.
The significant enhancement in the rheological and filtration properties, suggesting the applicability of using this additive as a rheology modifier and filtration control agent. These results showed the potential use of WSSSP as an alternative for some of the toxic materials used today in the oil and gas industry. This work demonstrates that this additive will help to reduce both the impact on the environment along with reducing the cost of drilling fluid and drilling waste handling.
A growing number of oil industry leaders are saying that data sharing across the industry is needed, but change is coming slowly. Could 2019 be a bumper year for offshore energy development? The very first fracturing job used sand scooped from a nearby river. After decades of buying sand based on tight size standards, unconventional operators are increasingly going back to a broad range of sizes, similar to that river sand. There is every reason to believe that enhanced oil recovery through huff-and-puff injections in US tight-oil plays could be a technical success across large numbers of wells.
Considering most of the rigs deal with human-machine interface systems, the role of human factors is at the heart of any successful operation. Eye-tracking technology can be useful in real-time operation centers where ocular movement data can improve the professionals’ performance. Environmentalists have sued a US agency to try to stop it from allowing oil and gas drilling on a vast stretch of federal land in Nevada, where the government is reversing protections put in place 9 months ago under the Obama administration. Two months after a Colorado home exploded near an Anadarko well, the reverberations are still rattling the oil industry, driving down driller shares and raising fears of a regulatory backlash. More than 100 members of Congress are urging the Trump administration not to open up the Atlantic or Pacific oceans for oil and gas drilling as part of the Interior Department’s review of federal offshore policies.