Hurlburt, Maurice (Athabasca Oil Corp.) | Quintero, Jonathan (Baker Hughes, a GE Company) | Bradshaw, Robert (Baker Hughes, a GE Company) | Belloso, Andres (Baker Hughes, a GE Company) | Cripps, Evan (Baker Hughes, a GE Company) | Blakney, Donya (Baker Hughes, a GE Company) | Glass, Darnell (Baker Hughes, a GE Company)
A Canadian oil & gas operator has been setting new benchmarks drilling the vertical and tangent section of Montney horizontal wells in the Placid field of Northern Alberta. Initially, the operator drilled vertical wells to kick off point (KOP) with polycrystalline diamond compacts (PDC) and conventional mud motors. As a result of increasing well density, however, the well plans consistently required a 15° to 30° tangent section. With PDC drilling, toolface and build up rates were problematic and the sliding rate of penetration (ROP) was slow.
A Rotary Steerable System (RSS) was introduced, but despite the improved performance, the technology came at a premium cost and the severity of drilling dysfunctions generated an increase in tool failures. With falling oil prices, a more cost effective solution was required.
Hybrid bit technology, which combines the cutting mechanism of both fixed cutter and roller-cone bits, has been extensively utilized in Canada to drill build sections, providing outstanding results. They have not, however, been commonly used to drill the vertical (drill-out) and tangent sections. The operator combined a state-of-the-art hybrid bit with a mud motor to drill the interval with an 85% success rate. The combination of the hybrid bit and conventional motor, compared to PDC and RSS, resulted in a 30% cost savings to complete the interval.
The present case study outlines how hybrid bit technology development, driven by field data in a continuous improvement cycle, identifies performance opportunities, which have a significant impact on drilling time and cost savings in drill out sections. The overall objective of this current case study is to highlight the results and lessons learned throughout the implementation process.
Mancilla-Polanco, Adel (University of Calgary) | Johnston, Kim (University of Calgary) | Richardson, William D. L. (University of Calgary) | Schoeggl, Florian F. (University of Calgary) | Zhang, Y. George (University of Calgary) | Yarranton, Harvey W. (University of Calgary) | Taylor, Shawn D. (Schlumberger-Doll Research)
The phase behavior of heavy-oil/propane mixtures was mapped from temperatures ranging from 20 to 180°C and pressures up to 10 MPa. Both vapor/liquid (VL1) and liquid/liquid (L1L2) regions were observed. Saturation pressures (VL1 boundary) were measured in a Jefri 100-cm3 pressure/volume/temperature (PVT) -cell and blind-cell apparatus. The propane content at which a light propane-rich phase and a heavy bitumen-rich (or pitch) phase formed (L1/L1L2 boundary) was visually determined with a high-pressure microscope (HPM) while titrating propane into the bitumen. High-pressure and high-temperature yield data were measured using a blind-cell apparatus. Here, yield is defined as the mass of the indicated component(s) in the pitch phase divided by the mass of bitumen in the feed. A procedure was developed and used to measure propane-rich-phase and pitch-phase compositions in a PVT cell.
Pressure/temperature and pressure/composition phase diagrams were constructed from the saturation-pressure and pitch-phase-onset data. High-pressure micrographs demonstrated that, at lower temperatures and propane contents, the pitch phase appeared as glassy particles, whereas at higher propane contents and temperatures, it appeared as a liquid phase. Ternary diagrams were also constructed to present phase-composition data. The ability of a volume-translated Peng-Robinson cubic equation of state (CEOS) (Peng and Robinson 1976) to match the experimental measurements was explored. Two sets of binary-interaction parameters were tested: temperature-dependent binary-interaction parameters (SvdW) and composition-dependent binary-interaction parameters (CDvdW). Models derived from both types of binary-interaction parameters matched the saturation pressures and the L1L2 boundaries at one pressure but could not match the pressure dependency of the L1L2 boundary or the measured L1L2 phase compositions. The SvdW model could not match the yield data, whereas the CDvdW model matched yields at temperatures up to 90°C.
Abdelfatah, Elsayed (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary) | Chen, Yining (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary) | Berton, Paula (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary) | Rogers, Robin D (525 Solutions, Inc.) | Bryant, Steven (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary)
Thermal and flotation processes are widely used to produce bitumen from oil sand in Alberta. However, bitumen contains many surface-active components that tend to form water-in-oil emulsion stabilized by fines and/or asphaltenes. Although several demulsifiers have been proposed in the literature to treat such emulsions, these chemicals are sometimes not effective. We propose ionic liquids whose composition has been designed to enable effective treatment of these emulsions.
Different ionic liquids were synthesized and tested for their efficiency in treating bitumen emulsion obtained from a field in Alberta. Ionic liquids tested are mixtures of organic bases with acids. Mixtures of ionic liquids and bitumen emulsion were prepared at several mass ratios. The two components were mixed under ambient conditions. After mixing, segregation of different components in the mixture was accelerated by centrifugation for rapid assessment of the degree of emulsion breaking. Optical microscopy, rheology, thermal gravimetric analysis, and viscosity measurements were used to assess the effect of ionic liquids on bitumen emulsions.
The first set of ionic liquids with cations of different alkyl chain lengths were able to separate the water from the emulsion. However, these ionic liquids tend to form a gel when mixed with water. The number and length of alkyl chains proved critical for avoiding gel formation. Ionic liquids with multiple long chains on the cation were immiscible with the separated water. These ionic liquids were very efficient in diluting and demulsifying bitumen emulsion. The emulsion droplet sizes increased upon addition of the ionic liquid. The ionic liquid mixes into the bitumen phase released from the emulsion, yielding a viscosity at ambient temperature close to the pipeline specifications.
This work demonstrates that ionic liquids can be tailored to break bitumen emulsions effectively without heat input. The process developed in this paper can replace current practice for the demulsification and dilution of bitumen emulsions, which requires the emulsion to be heated significantly. Hence the ionic liquid process reduces the heat requirements and hence greenhouse gas emissions.
Petroleum recovery from oilfield assets increasingly involves wells that are very long in extent and have multiple laterals, multiple tubing strings and multiple control points to prevent breakthrough of unwanted fluids and/or to optimize recovery. Instead of simply controlling rates at the wellhead, downhole devices are now available where apertures and other controlling parameters can be set statically, autonomously, or through surface intervention,. Having various control points in a wellbore that may include numerous flow paths requires a flexible setup and robust algorithms to effectively set all local constraints at various measured depths. This paper describes special constructs called "boundary segments" with a similar set of flow rate and pressure control modes to those available for tubinghead or bottomhole well control. In a multisegment well model whose topology consists of a set of nodes with intrinsic properties such as pressure, global mole fractions, total enthalpy, saturations, etc. and a set of pipes with attributes of length, volume, and a flow rate, these special segments share an existing node but have their own unique pipe together with boundary conditions and an accompanying set of control modes. Boundary segments are highly flexible, elegant, easy to implement, and useful in a variety of cases. This paper will provide reservoir simulation engineers and developers with an understanding of a simple method to calculate primary well control at the surface choke together with multiple downhole constraints from devices and tubing strings.
Cold heavy oil production with sand (CHOPS) is a non-thermal primary process that is widely adopted in many weakly consolidated heavy oil deposits around the world. However, only 5 to 15% of the initial oil in place is typically recovered. Several solvent-assisted schemes are proposed as follow-up strategies to increase the recovery factor in post-CHOPS operations. The development of complex, heterogeneous, high-permeability channels or wormholes during CHOPS renders the analysis and scalability of these processes challenging. One of the key issues is how to properly estimate the dynamic growth of wormholes during CHOPS. Existing growth models generally offer a simplified representation of the wormhole network, which, in many cases, is denoted as an extended wellbore. Despite it is commonly acknowledged that wormhole growth due to sand failure is likely to follow fractal statistics, there are no established workflows to incorporate geomechanical constraints into the construction of these fractal wormhole patterns.
A novel dynamic wormhole growth model is developed to generate a set of realistic fractal wormhole networks during the CHOPS operations. It offers an improvement to the Diffusion Limited Aggregation (DLA) algorithm with a sand-arch-stability criterion. The outcome is a fractal pattern that mimics a realistic wormhole growth path, with sand failure and fluidization being controlled by geomechanical constraints. The fractal pattern is updated dynamically by coupling compositional flow simulation on a locally-refined grid and a stability criterion for the sand arch: the wormhole would continue expanding following the fractal pattern, provided that the pressure gradient at the tip exceeds the limit corresponding to a sand-arch-stability criterion. Important transport mechanisms including foamy oil (non-equilibrium dissolution of gas) and sand failure are integrated.
Public field data for several CHOPS fields in Canada is used to examine the results of the dynamic wormhole growth model and flow simulations. For example, sand production history is used to estimate a practical range for the critical pressure gradient representative of the sand-arch-stability criterion. The oil and sand production histories show good agreement with the modeling results.
In many CHOPS or post-CHOPS modeling studies, constant wormhole intensity is commonly assigned uniformly throughout the entire domain; as a result, the ensuing models are unlikely to capture the complex heterogeneous distribution of wormholes encountered in realistic reservoir settings. This work, however, proposes a novel model to integrate a set of statistical fractal patterns with realistic geomechanical constraints. The entire workflow has been readily integrated with commercial reservoir simulators, enabling it to be incorporated in practical field-scale operations design.
Ni, Yidan (Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, AB CanadaT2N 1N4) | Ding, Boxin (Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, AB CanadaT2N 1N4) | Yu, Long (Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, AB CanadaT2N 1N4) | Dong, Mingzhe (Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, AB CanadaT2N 1N4) | Gates, Ian D. (Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, AB CanadaT2N 1N4) | Yuan, Yanguang (Bitcan Geosciences and Engineering Inc., Calgary, AB Canada T2A 2L5)
Steam-Assisted Gravity Drainage (SAGD) is a widely used technology for heavy oil and bitumen recovery in Alberta, Canada. However, a SAGD conformance problem arises due to the heterogeneity of oil sands reservoirs, such as the presence of high permeability zones and high water saturation zones. In particular, during a geomechanical dilation startup process that has been developed and applied in SAGD startup operations, the dilation fluid tends to flow into the high permeability zones, leaving the low permeability zones unswept. Therefore, the high permeability zones must be temporarily and selectively blocked off so as to more effectively dilate the low permeability zones along a SAGD well-pair. Laboratory permeability reduction tests in sandpacks by oil-in-water (O/W) emulsion injection showed that a permeability reduction of up to 99.95% can be achieved. Results of emulsion injection in parallelsandpack tests demonstrated that a good conformance control can be obtained by a suitable combinations of IFT, emulsion quality, emulsion slug size, and oil phase viscosity of an emulsion system. The reservoir simulation study was conducted to first match the laboratory test results and then to optimize SAGD conformance control operations by emulsion injection in heterogeneous oil sands reservoirs. A field-scale SAGD simulation model was established to show that emulsion injection during the dilation startup process can build up communication between the injector and producer, resulting in better steam chamber growth and lower cumulative steam-oil-ratio (CSOR).
Abouelresh, Mohamed (Center for Integrative Petroleum Research, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum and Minerals) | Khodja, Mohamed (Center for Integrative Petroleum Research, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum and Minerals) | Husseini, Rizwanullah (Center for Integrative Petroleum Research, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum and Minerals) | Al-Mukainah, Hani (Center for Integrative Petroleum Research, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum and Minerals) | Ali, Abdelwahab (Center for Integrative Petroleum Research, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum and Minerals)
Unconventional hydrocarbon resources continue to engender increasing attention as potential energy sources. This is reflected in the ongoing research aiming at gaining a better understanding of potential unconventional reservoirs. In this note, we describe a study focused on an organic-rich, potential gas-producer shale from Saudi Arabia, namely the Qusaiba Shale. The study aims, in particular, to quantify organic matter content, mineral content, and porosity using digital-rock methodology validated by laboratory measurements.
Rock plugs are selected from whole cores representative of the organic-rich, Qusaiba Shale. The core plugs are first digitized using high-resolution μ CT scan and the obtained 3D models are segmented to separate the total organic content (TOC) volume, rock matrix, and pore network. X-ray diffraction (XRD), X-ray fluorescence (XRF), and quantitative scanning electron microscopy (SEM) analyses are undertaken to determine elemental and mineralogical composition. To characterize porosity at a level adequate for shale, the samples also undergo SEM imaging, as well as nuclear magnetic resonance (NMR) analysis. Subsequently, numerical upscaling is applied and comparison of numerical and experimental results is performed.
Petrography and mineralogy analyses show that the major mineral components of the Qusaiba Shale samples are silica, feldspars, mica, clay, and pyrite. SEM imaging reveals that, at the nanoscale, the samples are characterized by a variety of pore types, sizes, and morphologies. Porosity comes in two types: intergranular and organic, with intergranular porosity being the dominant type. Compaction and horizontal alignment of the detrital mineral grains control the development of intergranular porosity while the distribution of organic particles, as well as their maturity, are the key factors controlling the formation of organic porosity. Integrating SEM images, high-resolution X-ray scans, and NMR measurements provides the information utilized to quantitatively determine the mineral and organic contents of the samples. Preliminary results exhibit a consistent agreement between the upscaled digital-rock-based estimates and the experimental measurements.
The main contribution of this study is an affordable, Digital Rock Physics (DRP)-based characterization of the organic content, mineral content, and pore-network structure of samples representative of Saudi Arabia's potential shale gas reservoirs that is consistent with laboratory measurements.
The Montney Formation is a major shale gas and shale oil producing stratigraphical unit of Lower Triassic age in the Western Canadian Sedimentary Basin in British Columbia and Alberta. The potential resource is estimated at 449 trillion cubic feet of marketable natural gas, 14,521 million barrels of marketable natural gas liquids (NGLs) and 1,125 million barrels of oil. The hydrocarbon resource is unlocked using horizontal drilling followed by various fracture stimulation techniques from 25 to 75+ stages. As stage counts increase and lateral lengths are extended further to stimulate more formation, the challenges of efficiently completing a producing well is a continuous cycle of technique development and equipment improvements.
Hydraulic isolation between fracture stimulation stages is established using mechanical methods deployed as an integral part of the production casing string or inserted into the production casing string during the fracture stimulation. In the Montney, the method of
The course will discuss the Huff-n-Puff gas EOR process specifically, but will also give a background in the relevant fundamentals of gas EOR methods (miscibility, vaporization, and displacement). Alternative EOR methods will also be discussed. The course is introduced by an industrywide summary of ongoing gas EOR projects in North American unconventionals.
It’s no secret that oil majors are among the biggest corporate emitters of pollution. What may be surprising is that they’re reducing their greenhouse-gas footprints every year, actively participating in a trend that’s swept up most corporate behemoths. The Canadian and Alberta governments and three energy companies said on 11 May that they will spend CAD 70 million (USD 51.14 million) to develop three new clean technology projects, aimed at cutting costs and carbon emissions in the country’s oil sands.