The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Zamani Ahmad Mahmoudi, Mohammad (AGH University of Science and Technology) | Khalilidermani, Mitra (AGH University of Science and Technology) | Knez, Dariusz (AGH University of Science and Technology)
Abstract Determination of the shear wave velocity, Vs, is an integral part in creation of reservoir geomechanical models. This parameter together with the compressional wave velocity and rock density are utilized to calculate the dynamic elastic moduli of the subsurface formations. In well logging, the Vs can be directly measured through the Dipole Shear Sonic Imager (DSI) logs which need special requirements and technical considerations. Therefore, many researchers have strived to develop cost-effective accurate methods for Vs estimation in the oil/gas fields. The Kharg Island offshore oilfields, located in the Persian Gulf, consist of a giant limestone reservoir called Asmari formation. In the past, numerous studies were conducted to develop mathematical relations for Vs prediction in the Asmari reservoir; however those relations were not capable of estimating the Vs values correctly. In this research, the well logging data related to a vertical offshore well was utilized to develop three mathematical relations for Vs estimation in the Asmari formation. To do this, linear regression (LR), Multivariate Regression (MLR), and Gene Expression Programing (GEP) methods were applied. Moreover, the accuracy of those relations was compared with some available empirical correlations for Vs prediction in limestone rocks. Comparing the results of those data-driven equations with the empirical equations illustrated that the results of the GEP method are more accurate than other equations. Moreover, the Pickett empirical correlation was found to be more suitable than other empirical correlations for Vs estimation in the Asmari reservoir. The methodology applied in this research is a reliable procedure to estimate the Vs in the study area as well as other geologically similar oil reservoirs. Such an application leads to generation of robust geomechanical models increasing the project success and oilfield development progression.
Abstract With the development of distributed fiber optic acoustic sensing technology in the field of borehole seismic surveys, more and more oil fields choose to pre-install fiber optics in the well in advance for borehole seismic data acquisition or fluid detection. In 2022, ADNOC completed the world’s first multi-well DAS VSP and OBN joint acquisition survey in the Persian Gulf, with the fiber placed outside the tubing, relying on the offshore high-density OBN acquisition survey, completing a total of 13 wells for DAS VSP acquisition. The DAS VSP raw data spacing interval is 1 m, the sampling interval is 1 ms, and the offshore air guns are staggered at a density of 25 m × 25 m. This study will focus on the determination of multi-well DAS VSP data acquisition area, data analysis for different Gauge Length, and raw data quality control.
A floating, production, storage, and offloading (FPSO)-based development in Nigeria is among the three finalists in contention for the 2023 International Petroleum Technology Conference (IPTC) Excellence in Project Integration Award. The award highlights projects with budgets of at least 500 million that have demonstrated distinction throughout the entire exploration and production value chain. The IPTC Excellence in Project Integration Award is given to a project that adds value to the industry and exemplifies strong teamwork, solid geoscience knowledge, reservoir and production engineering acumen, determined and watchful construction, and outstanding facilities engineering practices. The 2023 nominees are TotalEnergies' Egina development offshore Nigeria, Saudi Aramco's Fadhili Gas Plant in Saudi Arabia, and ExxonMobil's Liza Phase 1 and 2 off Guyana. The Egina project is the largest FPSO to date in the TotalEnergies SE fleet of FPSOs and the first deepwater project in Nigeria after the 2010 Nigerian Oil and Gas Industry Development Content Act.
In her first solo US exhibition, Berlin-based visual artist Monira Al Qadiri's Refined Vision will be featured at the Blaffer Art Museum in Houston until 8 January 2023. Qadiri, who grew up in Kuwait, centers on the theme of petroleum-centric cultures frequently in her work. Refined Vision is no exception. Drawing inspiration from the parallels of wealth and infrastructure between the Texas Gulf Coast and Persian Gulf, Qadiri hopes this exhibit will spark feelings of familiarity with viewers.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 208307, “A Water-Based Drilling Fluid for Controlling Deep-Reservoir Extreme Conditions in an Abu Dhabi Gas Shale Play,” by Gabe Manescu, SPE, Schlumberger; Balazs Veer, SPE, TotalEnergies; and Panamarathupalayam Balakrishnan, SPE, Schlumberger, et al. The paper has not been peer reviewed. _ A combination of teamwork and fluids technology proved to be the formula for successfully drilling in high-pressure/high-temperature (HP/HT) conditions for an onshore UAE shale gas play. The success achieved in drilling deep [6200-m measured depth (MD)], long-lateral-displacement (2,000-m) wells with an integrated global operator is a combination dependent on frequent, transparent communication between team members. The environmentally acceptable aqueous drilling fluid delivered a barite sag-free operation in these highly deviated wellbores. Introduction The drilling of unconventional HP/HT wells in the Diyab field can experience difficulty in reaching target depth. One significant challenge is the design of a drilling fluid to manage reservoir pressures and temperatures. The reservoir temperature may reach 165.5°C, requiring mud weights (MW) greater than 20 lbm/gal. Tailoring the drilling-fluid formulation to balance economics and environmental regulations while overcoming HP/HT conditions is critical. In the Diyab drilling campaign, special emphasis was placed on designing the drilling fluid and then on its use in 8½-in. reservoir sections. Background The Upper Jurassic (Oxfordian to Middle Kimmeridgian) Diyab formation, also known as the Dukhan formation, has served as the source rock for several major oil and gas fields in the Middle East. The Diyab formation is unique because of its lower porosities, high carbonate mineralogy, and pressure gradient. Despite the lower porosity, the high-carbonate content defines an extremely brittle target conducive to hydraulic fracture stimulation. Several organic-rich intervals exist throughout the Diyab formation and are separated by less-organic tight limestones, which create different flow units. From a developmental perspective, this condition has the potential to create a high-impact stacked play. The extent of the prospective unconventional Diyab formation within the UAE is limited to the onshore north-central UAE, where most of this area is within Block 1, operated by TotalEnergies. The depth of the prospective basal Diyab interval across Block 1 ranges between 3758 and 4115 m. Three unconventional offset wells (DE-02, DE-03, and DE-04) were drilled by ADNOC within Block 1 to test the productivity of the three submembers of the greater Diyab interval (the Jubaila, Hanifa, and Tuwaiq Mountain formations). After determining that the Hanifa formation had the most-promising productivity, the first TotalEnergies appraisal horizontal well, DE-05, was drilled. After drilling this well, the DE-06 well was the second horizontal appraisal well to be drilled. Additionally, two more deep wells, DE-09 and DE-10, were successfully drilled and evaluated.
An, Fuli (BGP,CNPC) | Chen, Xin (BGP,CNPC) | Xiao, Dengyi (BGP,CNPC) | Li, Xiaoliang (BGP,CNPC) | Ma, Cong (BGP,CNPC) | Peng, Bo (BGP,CNPC) | Zhao, Bo (BGP,CNPC) | Qi, Qunli (BGP,CNPC) | Wang, Bo (BGP,CNPC) | Li, Qiang (BGP,CNPC) | Liu, Caiqin (BGP,CNPC) | Gao, Xiaoli (BGP,CNPC)
Abstract The sequence stratigraphic framework based on the combination of core, lithofacies and logging curve cycles, sometimes hardly reflect the lithology and sedimentary changes between wells, and is inconsistent with seismic data and production performance. Through the integrated research of core, well logging, seismic data and reservoir engineering, this paper proposed an update method. The new method can effectively solve the geological challenges in exploration and development and provide a reliable geological basis for efficient production of the oilfield. This method includes the following 3 steps, (1) identify the sequence stratigraphic boundary integrated the core and lithofacies analysis, and establish the well correlation sequence stratigraphic framework. (2) According to seismic and geological calibration, realize mutual constraint between wells and seismic and robust the sequence stratigraphic framework. (3) The sequence stratigraphic framework is optimized by using production dynamic data, which could grab the sequence stratigraphic framework more consistent with the deposition law. The isochronous sequence stratigraphic framework established by this method in B oilfield of the Middle East truly restores the structural characteristics of the progradational strata of the main production layer in B oilfield, and the sequence boundaries match well between drilling data and seismic data. Under the control of the isochronous sequence stratigraphic configuration, the ambiguous results of the previous division in sublayers according to the lithological isopach were updated, which solved the problems of diachronous oil layer and disordered oil-water relationship in this oilfield. This study also provides an effective isochronous sequence stratigraphic unit for reservoir prediction in exploration and development. Compared with the previous sequence stratigraphy research method in this area, the new method has two major advantages, (1) It complements the shortage of uncertain between wells and increases the accuracy for uncored interval. Furthermore, this method establishes a real isochronous sequence stratigraphic framework. 2) Combined with production dynamic data, the challenge of diachronous sublayers and confusion of oil-water relationship in the research results are avoided.
Qatar is a desert peninsula in eastern Arabia with Saudi Arabia on its south and the remainder surrounded by the Persian Gulf (Figure 1). The peninsula is small --only 100 miles (160 km) from north to south--and 50 miles (80 km) from east to west. It plays home to a population of just under 3 million, of which approximately 10–15% are Qataris. Despite its small size and population, Qatar wields an outsized influence on the world stage as a direct consequence of its status as the world's largest liquefied natural gas (LNG) exporter. Before discovering oil and gas within its borders, Qatar's population was one of the poorest in the world.
Turner, Benjamin S. (Centre for Offshore Foundation Systems, Oceans Graduate School, The University of Western Australia) | Hossain, Muhammad S. (Centre for Offshore Foundation Systems, Oceans Graduate School, The University of Western Australia) | Ullah, Shah N. (School of Engineering and Technology, Central Queensland University) | Kim, Youngho (Centre for Offshore Foundation Systems, Oceans Graduate School, The University of Western Australia) | Mani, Usha (Centre for Offshore Foundation Systems, Oceans Graduate School, The University of Western Australia)
ABSTRACT Calcareous soils have been identified as problematic due to the special characteristics such as higher compressibility and softening, higher strain rate dependency as well as contractancy and dilatancy depending on the particle size (along with other factors). With the aim to propose an improved soil constitutive model for capturing the behaviour of calcareous silt, an experimental program on a range of reconstituted calcareous soils is undertaken for developing and calibrating the model. This paper investigates the undrained shearing response (as measured under triaxial compression conditions) of two calcareous soils of varying silt contents. The effect of particle size on the undrained shear strength and dilative or contractive response of calcareous soils is discussed. INTRODUCTION Calcareous soils cover over 35% of the ocean floor - prevalent in the Gulf of Mexico along the Florida coastline and in the Bay of Campeche, Arabo-Persian Gulf and the Red Sea, Southern Mediterranean Sea, offshore India and North West Shelf of Australia (ISO, 2016). Despite such widespread occurrence, the fundamental mechanical behaviours of these soils are not yet entirely understood, and have been identified as problematic due to the special characteristics such as high carbonate content, high compressibility, strong rate dependency and dilation after a phase transition (Mao & Fahey, 2003; Coop et al., 2004; Sharma & Ismail, 2006; Boukpeti & White, 2011; Miao & Airey, 2013). The aim of this paper is to investigate the effect of particle size on mechanical behaviour of reconstituted calcareous sediments. Calcareous sediments generally contain two polymorphs of calcium carbonate (CaCO3) – calcite and aragonite, and originate either through biogenic primary production or authigenic precipitation (Watson et al., 2019). Essentially the particles are highly angular, weak, fragile, and porous; and any deposit matrix consists of both intra and interparticle voids (Hyodo et al., 1996, 1998; Coop et al., 2004; Sharma & Ismail, 2006; Lehane et al., 2014; Lim et al., 2018). Microscopically, two main distinctive features of calcareous soils contribute to their specific behaviours: (i) the presence of intra-particle voids, and (ii) irregular shape of particles from microfossils such as coccoliths (Hyodo et al., 1996, 1998; Sharma & Ismail, 2006; Lim et al., 2018) (see Fig. 1). A clay from the Gulf of Mexico (Fig. 1c) is also included for comparison. The features result from the various chemical, physical, mechanical and biological deposition processes of skeletal remains of marine organisms in deep water. These distinctive features and 70~98% carbonate content of calcareous sediments have led to significantly higher liquidity index, sensitivity, in-situ void ratio, friction angles, compressibility, and strain rate dependency. The effect of mean particle size (d50) on undrained shearing behaviour was investigated by Mao & Fahey (2003) for two calcareous silts. The muddy silt (d50 = 0.001 mm) showed contractive behaviour, and the silt (d50 = 0.025 mm) showed dilative behaviour after a phase transition (see Fig. 2).
Abstract Offshore reservoirs in the Southwest Persian Gulf are commonly oil-wet limestone with an average permeability of 10 md. High production of hydrogen sulfide and carbon dioxide is often encountered in the oil producer wells. The tight reservoirs are commonly drilled with water-based reservoir drill-in fluid (DIF) with high concentrations of lubricants. DIFs based on sodium chloride or calcium chloride brines with corresponding optimal breakers to remove the filter cakes were formulated and evaluated to optimize production in newly drilled wells. Fluid displacement by return permeability (RP) testing was used to evaluate the fluid/limestone rock interaction. This paper discusses the compatibility of a sodium chloride-based and a calcium chloride-based DIF with limestone formation and the necessity of introducing an optimal breaker to maximize the opportunity to achieve high production rates. RP tests are widely used to determine the potential damage caused by the DIF and production enhancement after removing the DIF filter cake with a breaker. Desired results for RP tests performed with the brine-based DIF in limestone cores were a minimum of 75% regain permeability to oil production. The cores used for the RP tests were from an analogue limestone outcrop from a Mississippian formation with permeability between 9-16 md and 14-18% porosity. DIF properties were determined following API RP-13I recommended practices. Emulsion tendency for the fluids was determined by using emulsion tendency testing with a high-speed mixer to mimic shear at the pore throat. A 10.0 lb/gal sodium chloride water-based DIF with a high content of ester-based lubricant was designed for drilling a limestone formation. A high pH close to 10 was necessary to control H2S and CO2 corrosion. The return permeability of the 10.0 lb/gal fluid was 44% using LVT-200 oil as an analogue for the native hydrocarbon permeating fluid. The low return permeability was likely caused by emulsion blockages generated by the saponification of the ester-based lubricant used in the sodium chloride-based DIF. Emulsion tendency was observed between the DIF filtrate and permeating fluid in a fluid/fluid compatibility evaluation. Therefore, a breaker system was formulated and customized to enhance RP from 44% to a minimum of 75%. In contrast, a 11.0 lb/gal calcium chloride-based DIF with pH of 9.0 and same ester-based lubricant content was evaluated using a comparable limestone analogue core and demonstrated a high return permeability (>80%). Filtrate of the calcium chloride-based DIF did not form emulsions during fluid displacement in the RP test. Compatibility evaluation (return permeability) between drill-in fluids and reservoir rock is essential for oil producer wells in order to determine and avoid potential problems caused by interactions between them.
Abstract Following the increase in demand for natural gas production in the United Arab Emirates (UAE), unconventional hydraulic fracturing in the country has grown exponentially and with it the demand for new technology and efficiency to fast-track the process from fracturing to production. Diyab field has historically been a challenging field for fracturing given the high-pressure/high-temperature (HP/HT) conditions, presence of H2S, and the strike-slip to thrust faulting conditions. Meanwhile, operational efficiency is necessary for economic development of this shale gas reservoir. Hence "zipper fracturing" was introduced in UAE with modern technologies to enable both operational efficiency and reservoir stimulation performance. The introduction of zipper fracturing in UAE is considered a game changer as it shifted the focus from single-well fracturing to multiple well pads that allow for fracturing to take place in one well while the adjacent well is undergoing a pumpdown plug-and-perf operation using wireline. The overall setup of the zipper surface manifold allowed for faster transitions between the two wells; hence, it also rendered using large storage tanks a viable option since the turnover between stages would be short. Thus, two large modular tanks were installed and utilised to allow 160,000 bbl of water storage on site. Similarly, the use of high-viscosity friction reducer (HVFR) has directly replaced the common friction reducer additive or guar-based gel for shale gas operation. HVFR provides higher viscosity to carry larger proppant concentrations without the reservoir damage, and the flexibility and simplicity of optimizing fluid viscosity on-the-fly to ensure adequate fracture width and balance near-wellbore fracture complexity. Fully utilizing dissolvable fracture plugs was also applied to mitigate the risk of casing deformation and the subsequent difficulty of milling plugs after the fracturing treatment. Furthermore, fracture and completion design based on geologic modelling helped reduce risk of interaction between the hydraulic fractures and geologic abnormalities. With the application of advanced logistical planning, personnel proficiency, the zipper operation field process, clustered fracture placement, and the pump-down plug-and-perforation operation, the speed of fracturing reached a maximum of 4.5 stages per day, completing 67 stages in total between two wells placing nearly 27 million lbm of proppant across Hanifa formation. The maximum proppant per stage achieved was 606,000 lbm. The novelty of this project lies in the first-time application of zipper fracturing, as well as the first application of dry HVFR fracturing fluid and dissolvable fracturing plugs in UAE. These introductions helped in improving the overall efficiency of hydraulic fracturing in one of UAE's most challenging unconventional basins in the country, which is quickly demanding quicker well turnovers from fracturing to production.