Cold heavy oil production with sand (CHOPS) involves the deliberate initiation of sand influx during the completion procedure, maintenance of sand influx during the productive life of the well, and implementation of methods to separate the sand from the oil for disposal. No sand exclusion devices (screens, liners, gravel packs, etc.) are used. The sand is produced along with oil, water, and gas and separated from the oil before upgrading to a synthetic crude. To date, deliberate massive sand influx has been used only in unconsolidated sandstone (UCSS) reservoirs (φ 30%) containing viscous oil (μ 500 cp). It has been used almost exclusively in the Canadian heavy-oil belt and in shallow ( 800 m), low-production-rate wells (up to 100 to 125 m3/d).
The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine. First, the new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas technologies such as CHOPS can lower production costs in such basins. Fifth, technological feedback from heavy-oil production is improving conventional oil recovery. Finally, the heavy-oil resource in UCSS is vast. Although it is obvious that the amount of conventional (light) oil is limited, the impact of this limitation, while relevant in the short term (2000 to 2030), is likely to be inconsequential to the energy industry in the long term (50 to 200 years). The first discoveries in the Canadian heavy-oil belt were made in the Lloydminster area in the late 1920s. Typically, 10- to 12-mm diameter perforations were used, and pump jacks were limited by slow rod-fall velocity in the viscous oil to a maximum of 8 to 10 m3/d of production, usually less. Operators had to cope with small amounts of sand, approximately 1% in more viscous oils. Small local operators learned empirically that wells that continued to produce sand tended to be better producers, and efforts to exclude sand with screens usually led to total loss of production. Operators spread the waste sand on local gravel roads and, in some areas, the roadbeds are now up to 1.5 m higher because of repeated sand spreading. The sharp oil price increases in the 1970s and 1980s led to great interest in heavy-oil-belt resources (approximately 10 109m3). Many international companies arrived and introduced the latest screen and gravel-pack technology but, in all cases, greatly impaired productivity or total failure to bring the well on production was the result. To this day, there are hundreds of inactive wells with expensive screens and gravel packs. The advent of progressing cavity (PC) pumps in the 1980s changed the nonthermal heavy-oil industry in Canada. The first PC pumps had low lifespans and were not particularly cost-effective, but better quality control and continued advances led to longer life and fewer problems. The rate limits of beam pumps were no longer a barrier and, between 1990 and 1995, operators changed their view of well management.
Hart, Nicole (Premier Oilfield Group) | Dix, Michael (Premier Oilfield Group) | Mainali, Pukar (Premier Oilfield Group) | Rowe, Harold (Premier Oilfield Group) | Morrell, Austin (Premier Oilfield Group) | Matheny, Mei (Premier Oilfield Group)
The Powder River Basin (PRB) is an asymmetric foreland basin that historically hosted conventional oil plays, however, due to the development of evaluation and completion techniques for unconventional reservoirs, the PRB is being reevaluated for additional reserves. While PRB unconventional development has been limited thus far, the stacked potential of the Cretaceous section has become an intriguing prospect as the oil market recovers. Cretaceous unconventional targets in the PRB include two main source-rock intervals, the Mowry Shale and the Niobrara Formation, as well as tight and shaley siliciclastic reservoirs such as the Frontier, Turner, Shannon, and Sussex sandstones. Understanding mineral variation in these reservoir lithologies is essential for effective formation evaluation. Knowledge of clay and carbonate mineral abundances in the Mowry and Niobrara formations is particularly important, as these exert a first-order control on brittleness and permeability in these source rocks. Elemental data from cuttings have increasingly been used to model mineralogy, brittleness, and organic content in mudstone-dominated sequences. While this approach is well-established in other basins, it has not been rigorously attempted in the PRB.
An X-ray fluorescence (XRF) spectrometer with a customized reference-based calibration was used to collect quantitative data for 29 elements from wellbore cuttings. Mineralogy was then estimated from these elemental data using a stepwise element-parceling logic that was cross-checked against measured X-ray diffraction (XRD) mineralogy results. Elemental proxies for organic richness are also compared to TOC values. These established relationships can be utilized to develop a model for predicting TOC in the Mowry Shale and the Niobrara Formation.
Both XRF mineral modeling and XRD results indicated a wide range of quartz, calcite, clays, plagioclase-dominated feldspar, relatively low dolomite, and significant apatite. The total clay abundance of individual samples can exceed 50 weight percent, with mixed-layer illite/smectite, illite, and lesser amounts of chlorite and kaolinite represented. These preliminary results showed a strong correlation between the XRF-calculated mineralogy from the model and XRD-measured mineralogy in multiple stratigraphic units. The predominance of plagioclase over K-feldspar partially facilitates the accuracy of the model by simplifying the parceling of K2O into illite/smectite and illite. Additional preliminary results indicated that copper, molybdenum, uranium, and nickel correlated best with TOC and these relationships could potentially be used to model TOC in the Mowry and Niobrara.
Understanding mineral variation in these reservoir lithologies is essential because the abundances of clay and carbonate minerals largely dictate brittleness and permeability, and therefore the ability to fracture and produce hydrocarbons from these units. Additionally, a better understanding of the vertical distribution of TOC allows for improved well placement through the targeting of organic rich intervals. This workflow allows for effective formation evaluation through the rapid and economical collection of a versatile data set and model results that can be extrapolated to other wells to better understand the lateral and vertical variations in reservoir mineralogy and TOC across the southern PRB.
After a long cooling off period, this dry-gas shale play is once again red hot. Downhole annulus pressure is required for any gas lift design. This paper presents several methods of determining annulus pressure at depth and helps determine which method is most appropriate for specific conditions. The agency updated its methodology and production volume estimates to factor increasing production from new, emerging plays as well as older plays that have rebounded thanks to drilling advancements. UK’s first horizontal shale well has yielded positive results after an initial flow test.
Unconventional development has made it clear to Erdal Ozkan that conventional theory overlooks a lot of potentially productive rock. He talks about looking for ways to do better as part of JPT’s tech director report. The industry has figured out how much opportunity lies in the Permian Basin’s Delaware subbasin, and the Delaware play is now dominating US unconventional oil activity, Citigroup’s Jeff Sieler told the SPE Gulf Coast Section reservoir group recently. Unconventional Resources: Will Shale Oil Ever Make Money? This well-established oilfield consultancy explains why 2020 might be a big year for the unconventional sector.
The independent oil and gas company is aiming to build shareholder value through a change in business focus to midstream with this step into pipeline service and construction. The startup of a second FPSO will add 115,000 BOPD to the deepwater project offshore Angola, bringing overall production capacity to 230,000 BOPD. If sanctioned and developed, the deepwater Pecan field would be Ghana’s fourth producing offshore field. First oil is expected 35 months after sanction, which could come as early as this year. The combination will operate and share ownership of midstream gas assets in the Utica and Marcellus Shale plays.
Ashtead Technology has acquired Louisiana-based subsea equipment rental and cutting services specialist, Aqua-Tech Solutions, as part of the company’s international growth plans in the US. High-fidelity 3D engineering simulations are valuable in making decisions, but they can be cost-prohibitive and require significant amounts of time to execute. The integration of deep-learning neural networks with computational fluid dynamics may help accelerate the simulation process. The chemical reactions creating buildups of scale that can clog a well can be replicated in a chemical lab, but researchers are finding many more variables on the surfaces of pipes that need to be considered. ExxonMobil signed a sales and purchase agreement with Zhejiang Provincial Energy Group for LNG supply.
America’s hottest oil patch is producing so much natural gas that, by the end of last year, producers were burning off more than enough of the fuel to meet residential demand across the whole of Texas. Equinor has agreed to align its business model with the goals of the 2015 Paris climate accord and will review its corporate lobbying policy and the carbon intensity of its products, the company said. It will also link executive pay to climate-related targets. A wave of satellites set to orbit the Earth will be able to pinpoint producers of greenhouse gases, right down to an individual leak at an oil rig. Scientists from the University of East Anglia have discovered a unique oil-eating bacteria in the deepest part of the Earth’s oceans—the Mariana Trench. A bipartisan group of senators introduced a bill to increase federal funding toward developing carbon capture technology while also committing to fossil fuel use. Oilfield wastewater disposal volumes are expected to double in the Permian Basin within the next 2 to 3 years, a new analysis from global energy intelligence firm Wood Mackenzie shows.
Ashtead Technology has acquired Louisiana-based subsea equipment rental and cutting services specialist, Aqua-Tech Solutions, as part of the company’s international growth plans in the US. High-fidelity 3D engineering simulations are valuable in making decisions, but they can be cost-prohibitive and require significant amounts of time to execute. The integration of deep-learning neural networks with computational fluid dynamics may help accelerate the simulation process. The chemical reactions creating buildups of scale that can clog a well can be replicated in a chemical lab, but researchers are finding many more variables on the surfaces of pipes that need to be considered. The web-based interactive tool provides users specialized “ocean neighborhood analyses,” including maps and graphics by analyzing more than 100 ocean datasets instantaneously. BP and partners have sanctioned the Azeri Central East project, the next stage of development of the giant Azeri-Chirag-Deepwater Gunashli oilfield complex in the Azerbaijan sector of the Caspian Sea. The pipeline system will have the initial capacity to deliver 150,000 B/D of crude oil to multiple delivery points, accessing local refineries and connecting to several downstream pipelines.
One of the considerations in hydraulic fracturing treatment optimization in unconventional (shale/tight/CBM) reservoirs is creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. However, actual field experience has shown that some reservoirs under certain treatment designs exhibit excessive fracture complexity due to excessive induced stresses or stress shadowing that can result in pressureout or screenout, and thus, poor well completion and productivity performance. Therefore, it is crucial to identify the reservoir candidates and treatment strategies that are suitable for enhancing fracture complexity to avoid fracturing treatment scenarios that will have an adverse effect on the well productivity.
In this work, a three-dimensional hydraulic fracture extension simulator is coupled with a reservoir production simulator to screen for the reservoir candidates and fracturing treatment scenarios that can lead to enhancing fracture complexity, conductivity, and connectivity and positive well production performance. Furthermore, scenarios are identified under which excessive fracture complexity (due to excessive induced stresses or stress shadowing) results in poor well completion performance.
The results indicate that fracture complexity can be enhanced under the following treatment scenarios: (1) low-viscosity slickwater with smaller proppant sizes under high treatment rates, (2) hybrid fracture treatment (low-viscosity slickwater containing smaller proppants and low proppant concentrations with high treatment rates followed by viscous treatment fluids containing larger proppants and higher proppant concentrations), (3) simultaneous fracturing of multiple intervals at close spacing, and, (4) out-of-sequence pinpoint fracturing (fracturing Stage 1 and then Stage 3 followed by placing Stage 2 between the previously fractured Stages 1 and 3). It is also revealed that the success of each of the above treatment scenarios is very sensitive to rock brittleness (combination of Young's modulus and Poisson's ratio), magnitude of stress anisotropy, matrix permeability, process zone stress/net extension pressure, fracture gradients, and treatment fluid viscosity and rate. Additionally, excessive fracture complexity, which impedes fracture growth due to pressure out and screenout, can be mitigated by reducing treatment rate and pressure, increasing treatment fluid viscosity, and using small particulates, such as 100-mesh proppant.
This work is the first attempt in comparative evaluation of the impact of creating fracture complexity under a variety of operationally-feasible treatment scenarios applied to a wide range of reservoir and rock geomechanical properties. It shows that wells with certain combinations of Young's modulus, Poisson's ratio, stress anisotropy, and fracture gradients are not suitable candidates for creating complexity in the hydraulic fractures system.