Fed by big data loads from big operators, a university consortium and software firm are each working to make upstream data access as quick and easy as a Google search. Pictures shot in fractured wells show how a high-pressure slurry of water and sand carves up the perforations. Industry confidence is on the rise, and so is capital spending, according to DNV’s 2019 annual outlook. 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.
An assortment of sustainability initiatives shows how the oil and gas industry, leveraging its reach, diversity, and resources, is going well beyond just supplying energy to impact the world for the better. JPT asked several active SPE members about the appeal of petroleum engineering, the significance of the work they do, and what the future may hold. Did I Make the Right Career Choice? JPT asked several active young professionals about their career path thus far and what they liked about petroleum engineering. Here are some of their answers. We are in the midst of an energy transition: the world is moving quickly and inevitably away from “dirty” fossil fuels to “green” solar, wind, and batteries.
Latest News are articles brought to you online only and have not been published in an issue of JPT. Yellowtail-1 is the fifth discovery in the Turbot area, where ExxonMobil plans another Stabroek Block development hub. With the purchase, the growing, privately-held Chrysaor Holdings will expand its UK North Sea production to 185,000 BOE/D.
Salehabadi, Manoochehr (Shell UK Exploration & Production) | Susanto, Indriaty (Shell UK Exploration & Production) | Prin, Cindy (Shell UK Exploration & Production) | Freeman, Christopher (Shell UK Exploration & Production) | Laird, Rebecca (Shell UK Exploration & Production) | Gernnaro, Sergio De (Shell UK Exploration & Production) | Forsyth, Gatsbyd (Shell UK Exploration & Production) | Doornhof, Dirk (Nederlandse Aardolie Maatschappij B.V.)
Strong reservoir pressure depletion after years of production in a high pressure, high temperature (HP/HT) oil field in the UK Central North Sea led to reservoir compaction and stress changes in the overburden, which consequently had an impact on the fracture gradient profile. The understanding of the current fracture gradient is essential as it is one of the two key process safety inputs for further drilling or abandonment design. Besides ensuring hydrocarbons are kept within the reservoir/subsurface by assessing the caprock integrity, the ability to accurately estimate the fracture gradient range can potentially provide significant savings in the design and concept select phases, especially for HP/HT fields as most investments are very capital intensive. Stress changes in the overburden rock due to reservoir compaction ("stress arching effect") can be observed from the Time Lapse (4D) seismic data as a velocity slow down due to overburden stretching/ expansion. An integrated study was conducted by developing a 3D geomechanical model and coupling with 4D seismic data to assess the current fracture gradient in the overburden, specifically in the caprock. The results of this study show that overburden weakening is strongest at the top of the reservoir and extends up to mid overburden. The lateral extent of the weakening is confined by the area of the depleted reservoir. In this paper, we demonstrate the benefits of understanding the current fracture gradient, both for abandonment design by optimising the number of cement plug isolations and their location as well as for assessing the caprock integrity during long term abandonment.
Sun, Zhe (CNOOC Research Institute Co., Ltd.) | Kang, Xiaodong (CNOOC Research Institute Co., Ltd.) | Tang, Xiaoxu (CNOOC China Limited, Tianjin Branch) | Wu, Xingcai (Research Inst. of Petroleum Exploration and Development) | Li, Qiang (Development and Production Department, CNOOC Ltd.) | Wang, Yu (CNOOC China Limited, Tianjin Branch) | Wang, Tianhui (CNOOC China Limited, Tianjin Branch) | Zhang, Hong (CNOOC China Limited, Tianjin Branch)
Bohai offshore oilfield in China is characterized by high oil viscosity, strong reservoir heterogeneity and big inter-well distances, which leads to the breakthrough of injection water in deep reservoirs with poor sweep efficiency and development effect. To solve this problem, this paper evaluated the performance of self-adaptive microgel system (SMG), and introduced its application in field trial.
The self-adaptive microgel is a kind of microsphere in various sizes with strong deformation ability. In this paper, the physical and chemical properties of the self-adaptive microgel are studied by means of metallographic microscope and the statistical principle. Also, the extreme permeability value of the self-adaptive microgel which allows it to flow though the core is determined through core flow experiments and the evaluation method of resistance factor and residual resistance factor. Furthermore, a long core is used to evaluate the fluid diversion ability of the self-adaptive microgel under the condition of constant speed and constant pressure flooding. Finally, a field trial case study of the self-adaptive microgel is analyzed.
Experiment results suggest that the self-adaptive microgel has good water swelling properties, narrow particle size distribution, huge inaccessible pore volume and large accessible pore volume of its carrier fluid. When the self-adaptive microgel with micron and submillimeter particle size flow through the core and the injection pressure stays stable, the permeability limit is 237×10−3μm2 and 712×10−3μm2, respectively. Since the self-adaptive microgel enters larger pores and generates plugging effect, while its carrier liquid enters smaller pores and displaces oil. So it obtains combined effects of "plugging" and "flooding". Moreover, the oil increment of the self-adaptive microgel under constant pressure flooding is higher than that under constant speed flooding. The case study shows that self-adaptive microgel flooding can increase oil production and reduce water cut obviously, which obtains technical and economic success.
Also, this paper preliminarily establishes a property evaluation method for the self-adaptive microgel, analyzes its mechanism and displacement effect. Furthermore, the field trial effect of self-adaptive microgel flooding is explored. In summary, the research results provide a theoretical basis and technical support for the application of self-adaptive microgel flooding technology.
BHGE is developing an analytics and machine-learning approach that offers descriptive and predictive insights on frac hits, with the aim of eventually offering a real-time monitoring capability to be deployed during frac jobs. Earlier this year in Aberdeen many of the oil and gas industry’s innovation champions met to discuss the developments that are driving the digital transformations within operators and service providers alike. The shift toward lower prices in the industry has resulted in the necessity for more wells to be drilled at lower cost. Numerous other industries have shown that they are able to constantly reduce cost per unit.
The 11 wells at the Hydraulic Fracturing Test Site were fractured in 2015 using what was then a fairly new method, zipper fracturing. Rather than pumping one well at a time, wells were fractured them in groups—four pairs, plus three wells together in the middle of the pattern. Zipper fracturing speeds work by allowing continuous pumping and it reduces the risk of frac hits because the method only fractures rock where pressure has not been depleted by production. Now zipper fracturing is used to fracture even more wells at once. What researchers found at the fracturing test site was that zipper fractures create strong connections.
The Constrained Pressure Residual (
The two-stage ECPR preconditioning uses an expanded variable set for the first stage. The key step involves a fast strong variable selection algorithm which can substantially increase the robustness of CPR. For the approximate solution of this enhanced first stage we used FGMRES with equilibrated ILUC as the preconditioning. The improved strength of this step allows the use of a less expensive second stage preconditioning such as block ILU(0) rather than block ILU (1)
The block ILU(0) /ECPR method showed significant improvement in convergence rate for these difficult thermal cases over the original block ILU(1)/CPR method. We observed over 50% reduction in the number of iterations for our moderately difficult test cases over entire runs and reduction in run times. For individual linear systems requiring many CPR iterations test cases show iterations can be reduced by 80% or more using ECPR. In one particular test case CPR failed to converge after 100 iterations but ECPR converged in 7 iterations.
Li, Zaoyuan (Southwest Petroleum University) | Cheng, Xiaowei (Southwest Petroleum University) | Zhang, Mingliang (Southwest Petroleum University) | Wu, Xingru (University of Oklahoma) | Wu, Shuang (Geology Institute of Liaohe Lengjia Oilfield Development Company) | Wu, Dongkui (Research Institute of Liaohe Oilfield Drilling Technology) | Xiao, Yunfeng (Research Institute of Liaohe Oilfield Drilling Technology)
According to the requirements of rapid setting at low temperatures and long-term performance during high-temperature production on cementing for heavy oil thermal recovery wells, this study proposes the application of aluminate cement to cementing of heavy oil thermal recovery wells. Against the background of operation conditions in Liaohe Oilfield, the strength decline mechanism of the conventional silicate cement stone added silica sand were evaluated by simulating the high-low temperature circulating humid environment that the cement sheath of the heavy oil thermal recovery well faced with. Then, through laboratory experiments, the research compounded a kind of mineral clinker based on aluminate cement, prepared fluid loss agent J73S and retarder SR compatible with aluminate cement and designed a new-type thermostable aluminate cement slurry system with an applicable density range of 1.70g/cm3~1.90g/cm3 and temperature range of 30°~80°. Moreover, the hydration product and the thermostable mechanism of the modified aluminate cement slurry were analyzed through this simulation. According to the results, with the crystalline transforming at high temperatures, the strength of conventional silicate cement with silica sand substantially declines under the condition of multi-cycle high-low temperature circulation, therefore it cannot satisfy the cementing requirement of thermal recovery wells effectively. The thermostable aluminate cement slurry system features excellent engineering performance: the slurry density difference is lower than 0.02 g/cm3, the fluid loss is less than 50 ml, the thickening time is adjustable from 60 min to 300 min, the 24h strength is up to 14 MPa, and the compressive strength of cement slurry can still reach 25 MPa after two rounds of high-temperature testing. In addition, the SiO2 in the additives massively participate in the hydration reaction, endowing the modified aluminate cement slurry with favorable thermostable performance and long term stability. The application of the cement slurry system to cementing for heavy oil thermal recovery wells of Liaohe Oilfield exhibits a smooth operation process and excellent cementing quality, so it can efficiently satisfy the cementing operation requirement of heavy oil thermal recovery wells efficiently.