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Cold heavy oil production with sand (CHOPS) is a relatively recent technology. As such, only a few case histories of its application over a number of years have been published. Nonetheless, those that are available provide insight into the application of this technology. A detailed Luseland field case history has been published. It had a long history (12 to 15 years) of slow production with reciprocating pumps, an attempt to produce with horizontal wells (6 wells, all failures), and then a conversion to CHOPS through reperforation and progressing cavity (PC) pump installation.
Shell Trinidad and Tobago, through BG International, a subsidiary of Royal Dutch Shell plc, has started production on Block 5C in the East Coast Marine Area in Trinidad and Tobago. Block 5C, known as Project Barracuda, is a backfill project with approximately 140 MMcf/D of sustained near-term gas production with peak production expected to be about 220 MMcf/D. It is Shell's first greenfield project in the country and one of its largest in Trinidad and Tobago since the BG Group acquisition. "Today's announcement strengthens the resilience and competitiveness of Shell's position in Trinidad and Tobago," said Maarten Wetselaar, director of integrated gas, renewable, and energy solutions for Shell. "This is a key growth opportunity that supports our long-term strategy in the country as well as our global LNG growth ambitions."
Conventional well completions in soft formations (the compressive strength is less than 1,000 psi) commonly produce formation sand or fines with fluids. These formations are usually geologically young (Tertiary age) and shallow, and they have little or no natural cementation. "Friable" and "Unconsolidated" are two commonly used terms to describe the nature of the reservoir material. Sand production can plug tubing, casing, flowlines and surface vessels. It can erode equipment that leads to loss of well control or unwanted fluid emissions.
In this new decade, the prevalence of integration is at the forefront of the scientific community. Every discipline, scientist, or company has a way in which they define the term “integration.” Regardless of how you define the effort that links disciplines quantitatively, the importance of constraining subsurface characterization to link it to production results and drive toward a predictive model is a critical accomplishment for our industry.
Kalhor Mohammadi, Mojtaba (International Drilling Fluids) | Taraghikhah, Shervin (International Drilling Fluids) | Karimi Rad, Mohammad Saeed (International Drilling Fluids) | Tahmasbi Nowtaraki, Koroush (International Drilling Fluids)
Abstract Developing high-performance environmentally friendly drilling fluids is always a requirement by oil and gas operators to reduce the waste management associated cost with the drilling fluid treatment and disposal. Conventional water-based drilling fluid is formulated with the brine-based polymer which consists of sodium and potassium chloride salts to improve the performance of the polymer and also providing clay inhibition in reactive clay and shale. This paper describes the development of nanotechnology-based drilling fluid to replace salt from the conventional application. Nano Based Low Saline Water Based Mud (NBLS-WBM) was formulated and developed based on laboratory experiments. Different nano additives with different concentrations were evaluated and the optimum concentration was selected to reduce the sodium and potassium chloride salts concentration to almost zero. The rheological properties and fluid loss were measured according to the API standard before and after hot rolling. Also, HPHT fluid loss, lubricity, and shale inhibition were evaluated. All the results were compared with sodium salt-saturated and potassium-based polymer muds. Laboratory evaluation of NBLS-WBM indicated that sodium salt concentration can be reduced considerably up to 5% W/V and potassium chloride can be eliminated by adding 1% W/W of nano additive. The rheological properties including plastic viscosity and yield point were constant and stable after hot rolling 16 hours at 250 °F. Also, Clay inhibition improved significantly up to 95% recovery comparing with conventional water-based polymer mud. Although the application of nanotechnology to improve the performance of conventional water-based drilling fluid was studied by many researchers, it is the novelty of this research to reduce the salt concentration and remove it to develop the new generation of salt-free water-based drilling fluid with economical consideration and lower environmental impact.
Abstract Distributed Fiber Optics (DFO) technology has been the new face for unconventional well diagnostics. This technology focuses on measuring Distributed Acoustic Sensing (DAS) and Distrusted Temperature Sensing (DTS) to give an in-depth understanding of well productivity pre and post stimulation. Many different completion design strategies, both on surface and downhole, are used to obtain the best fracture network outcome; however, with complex geological features, different fracture designs, and fracture driven interactions (FDIs) effecting nearby wells, it is difficult to grasp a full understanding on completion design performance for each well. Validating completion designs and improving on the learnings found in each data set should be the foundation in developing each field. Capturing a data set with strong evidence of what works and what doesn't, can help the operator make better engineering decisions to make more efficient wells as well as help gauge the spacing between each well. The focus of this paper will be on a few case studies in the Bakken which vividly show how infill wells greatly interfered with production output. A DFO deployed with a 0.6" OD, 23,000-foot-long carbon fiber rod to acquire DAS and DTS for post frac flow, completion, and interference evaluation. This paper will dive into the DFO measurements taken post frac to further explain what effects are seen on completion designs caused by interferences with infill wells; the learnings taken from the DFO post frac were applied to further escalate the understanding and awareness of how infill wells will preform on future pad sites. A showcase of three separate data sets from the Bakken will identify how effective DFO technology can be in evaluating and making informed decisions on future frac completions. In this paper we will also show and discuss how DFO can measure real time FDI events and what measures can be taken to lessen the impact on negative interference caused by infill wells.
Sochovka, Jon (Liberty Oilfield Services) | George, Kyle (Liberty Oilfield Services) | Melcher, Howard (Liberty Oilfield Services) | Mayerhofer, Mike (Liberty Oilfield Services) | Weijers, Leen (Liberty Oilfield Services) | Poppel, Ben (Liberty Oilfield Services) | Siegel, Joel (Liberty Oilfield Services)
Abstract The shale industry has changed beyond recognition over the last decade and is once again in rapid transition. While we are unsure about the nature of innovations to make US shale ever more competitive, we are certain that the current downturn will drive a further reduction in $/BO – the total cost to lift a barrel of US shale oil to the surface. As a result of an increase in scale and industry efficiency gains, the all-in price charged by service companies to place a pound of proppant downhole has come down from more than $0.50/lb in 2012 to about $0.10/lb today. In this paper, we discuss what components have contributed to this reduction to date and use several case studies to illustrate the potential for further cost reductions. The authors used FracFocus data to study a variety of placement and production chemicals for about 100,000 horizontal wells in US liquid rich basins, including the Williston, Powder River, DJ, Permian basins, as well as SCOOP/STACK and Eagle Ford. All chemicals used were averaged on a per-well basis into a gallon-per-thousand gallons (gpt) metric. In the paper, we first provide an overview of trends by basin since 2010 for these chemical additives. Then, we perform Multi-Variate Analysis (MVA) to determine if groups of these chemicals show an impact on production performance in specific basins or formations. Finally, through integration of lab testing (on fluid systems and proppants), a liquid-rich shale production database and FracFocus tracking of industry trends, the authors developed a list of case histories that show modest to significant reductions in $/BO. In this paper we focus on proppant delivery cost – the cost to place a pound of proppant in a fracture downhole, where it can contribute to a well's production for years to come. The last decade saw a 10-fold increase in horsepower, a 20-fold increase in yearly stages pumped and a 40-fold yearly proppant mass increase. One result of this increase in scale, was a gain in efficiencies, which led to an average 3-fold fracturing cost decrease to place a pound of proppant downhole. We will document this trend in detail in the paper. A significant industry trend over the last decade has been a "viscosity for velocity" trade. The change to smaller mesh regional proppants, in combination with an increase in pump rates on frac jobs in the US, has allowed fluid systems to become more "watery". At the same time, the industry is moving from guar systems to polyacrylamide-based systems that exhibit higher apparent viscosities at low to ultra-low shear rates. These newer High Viscosity Friction Reducer (HVFR) systems show superior proppant carrying capacity over traditional slickwater fluid systems. Regained conductivity testing has shown that these HVFR systems are generally cleaner for fracture conductivity than guar systems. Along with changes to base chemistry, a 2- to 5-fold increase in disposal costs and an overall "green initiative" over the last decade have resulted in a push to maximize recycled water usage on these HVFR jobs. These waters can be in excess of 150,000 TDS (Total Dissolved Solids) which present challenges across the board when designing a compatible fluid system that fits the needs in terms of viscosity yield, scale inhibition and microbial mitigation etc. – all while keeping costs low. Specialty chemicals, such as Hydrochloric Acid (HCl) substitutes that have similar efficacy as HCl but significantly lower reactivity with human skin, have helped significantly to improve operational safety around previously-categorized hazardous chemicals, and have helped reduce cost and improve pump time efficiency. Measurement of bacterial activity during and after fracture treatments can help with the best economic selection of the appropriate biocide. These simple measurements can help further reduce what is spent on the necessary chemical package to effectively treat a well. This paper provides a holistic view of fluid selection issues and shows a real-data focused methodology to further support a leaner approach to hydraulic fracturing.
Rodríguez-Pradilla, Germán (School of Earth Sciences, University of Bristol, UK.) | Eaton, David (Department of Geoscience, University of Calgary, Canada.) | Popp, Melanie (geoLOGIC Systems Ltd., Calgary, Canada.)
Abstract The goal of this work is to calibrate a regional predictive model for maximum magnitude of seismic activity associated with hydraulic-fracturing in low-permeability formations in the Western Canada Sedimentary Basin (WCSB). Hydraulic fracturing data (i.e. total injected volume, injection rate, and pressure) were compiled from more than 40,000 hydraulic-fractured wells in the WCSB. These wells were drilled into more than 100 different formations over a 20-year period (January 1st, 2000 and January 1st, 2020). The total injected volume per unit area was calculated utilizing an area of 0.2° in longitude by 0.1° in latitude (or approximately 13x11km, somewhat larger than a standard township of 6x6 miles). This volume was then used to correlate with reported seismicity in the same unit areas. Collectively, within the 143 km area considered in this study, a correlation between the total injected volume and the maximum magnitude of seismic events was observed. Results are similar to the maximum-magnitude forecasting model proposed by A. McGarr (JGR, 2014) for seismic events induced by wastewater injection wells in central US. The McGarr method is also based on the total injected fluid per well (or per multiple nearby wells located in the same unit area). However, in some areas in the WCSB, lower injected fluid volumes than the McGarr model predicts were needed to induce seismic events of magnitude 3.0 or higher, although with a similar linear relation. The result of this work is the calculation of a calibration parameter for the McGarr model to better predict the magnitudes of seismic events associated with the injected volumes of hydraulic fracturing. This model can be used to predict induced seismicity in future unconventional hydraulic fracturing treatments and prevent large-magnitude seismic events from occurring. The rich dataset available from the WCSB allowed us to carry out a robust analysis of the influence of critical parameters (such as the total injected fluid) in the maximum magnitude of seismic events associated with the hydraulic-fracturing stimulation of unconventional wells. This analysis could be replicated for any other sedimentary basin with unconventional wells by compiling similar stimulation and earthquake data as in this study.
Hui, Gang (University of Calgary, Alberta, Canada) | Chen, Shengnan (University of Calgary, Alberta, Canada) | Gu, Fei (PetroChina Research Institute of Petroleum Exploration and Development, Beijing, China)
Abstract The recent seismicity rate increase in Fox Creek is believed to be linked to the hydraulic fracturing operations near the region. However, the spatiotemporal evolution of hydraulic fracturing-induced seismicity is not well understood. Here, a coupled approach of geology, geomechanics, and hydrology is proposed to characterize the spatiotemporal evolution of hydraulic fracturing-induced seismicity. The seismogenic faults in the vicinity of stimulated wells are derived from the focal mechanisms of mainshock event and lineament features of induced events. In addition, the propagation of hydraulic fractures is simulated by using the PKN model, in combination with inferred fault, to characterize the possible well-fault hydrological communication. The original stress state of inferred fault is determined based on the geomechanics analysis. Based on the poroelasticity theory, the coupled flow-geomechanics simulation is finally conducted to quantitatively understand the fluid diffusion and poroelastic stress perturbation in response to hydraulic fracturing. A case study of a moment-magnitude-3.4 earthquake near Fox Creek is utilized to demonstrate the applicability of the coupled approach. It is shown that hydraulic fractures propagated along NE45° and connected with one North-south trending fault, causing the activation of fault and triggered the large magnitude event during fracturing operations. The barrier property of inferred fault under the strike-slip faulting regime constrains the nucleation position of induced seismicity within the injection layer. The combined changes of pore pressure and poroelastic stress caused the inferred fault to move towards the failure state and triggered the earthquake swarms. The associated spatiotemporal changes of Coulomb Failure Stress along the fault plane is well in line with the spatiotemporal pattern of induced seismicity in the studied case. Risks of seismic hazards could be reduced by decreasing fracturing job size during fracturing stimulations.
Yang, Xinxiang (University of Alberta (Corresponding author) | Kuru, Ergun (email: firstname.lastname@example.org)) | Gingras, Murray (University of Alberta) | Biddle, Sara (University of Alberta) | Lin, Zichao (University of Alberta) | Iremonger, Simon (University of Alberta)
Summary Cement-rock interface is a major component of the wellbore barrier system. Leakage may result from the poor bonding between cement and rock interface. In this paper we investigate possible factors that may affect the cement-rock interface bonding. More specifically, integrity of the cement-rock interface was characterized using micro-computed tomography (CT) and environmental scanning electron microscopy (ESEM). Hollow cylinder rock samples were prepared by using rock samples (e.g., Banff dolostone, Pekisko limestone, Doig sandstone, Notikewin siltstone, Montney siltstone, and Wilrich siltstone) collected from different Alberta wells at various depths. Two abandonment cement blends were injected into the rock open hole. By using ESEM (0.05-mm resolution) and micro-CT (11.92-mm resolution) techniques, the 2D and 3D models of the cement-rock interface were developed. Energy-dispersive X-ray spectroscopy (EDS) was conducted to analyze chemical characteristic of the cement-rock samples. Using the CT images, computational fluid dynamics (CFD) models were built to simulate fluid flow through the cement-rock samples. For both cement and rock, there is a nonuniform porosity distribution in radial and axial directions. For most of the cement-rock samples, the highest porosity region in the cement column was found at the cement-rock interface. Optimizing the chemistry of the cement system enhances the cement-rock interface bond by effectively reducing the gap between cement and rock observed in ESEM images. Although cement migration was observed in the rough rock surface in porous rocks, the rock interface and matrix zones have almost identical element concentrations. For the investigated samples, the chance for significant chemical reaction at the cement-rock interface is minimal. CFD simulation based on digital cement models showed that the cement-rock interface has more chance to act as the main flow pathway when intact (low permeability) caprock exists. The sample preparation, image analysis and simulation methods used in this study can be also applied to other cement interface studies (e.g., cement-casing, casing-cement-rock). From the practical field application point of view, the results presented here would help to have a better understanding of the requirements for designing optimum cement formulations to establish effective zonal isolation and reduce the greenhouse gas emissions from oil and gas wells. Introduction Wellbore cement is the most important barrier element because it provides zonal isolation to prevent uncontrolled flow of formation fluid to the surface as well as crossflow among various underground formations.