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Moving their directional drillers into their Houston real-time remote operations centers has improved drilling efficiency for two of the top shale producers. This paper presents an interdisciplinary approach to the description of tectonic dislocations made on the basis of interpretation of seismic data, petrophysical analysis of well-logging data in horizontal wells, and inversion of a multifrequency propagation tool. This work presents a systematic geosteering work flow that automatically integrates a priori information and real-time measurements to update geomodels with uncertainties and uses the latest model predictions in a decision-support system (DSS). The use of intelligent software is on the rise in the industry and it is changing how engineers approach problems. A series of articles explores the potential benefits and limitations of this emerging area of data science.
This paper presents a coupled 3D fluid-flow and geomechanics simulator developed to model induced seismicity resulting from wastewater injection. Knowing which horizon crude oil flows from and in what proportions has been a major challenge for shale producers. Increasingly, they are turning to new technology to find the answer. Seismic imaging provides vital tools for the exploration of potential hydrocarbon reserves and subsequent production-planning activities. The acquisition of high-resolution, regularly sampled seismic data may be hindered by physical or financial constraints.
A new licensing round will open up 136 blocks in the Arctic Barents Sea. Neptune must pay Energean a break-up fee of $5 million for cancelling what was to be a $250 million deal. For the offshore sector, the collapse in oil demand and prices came just as the market was beginning to look up. Now many companies are focused on survival. This article discusses how various market segments, regions, and companies are faring in “the new reality.”
Africa (Sub-Sahara) An 816-mile 2D seismic acquisition program was completed on the Ampasindava block, located in the Majunga deepwater basin offshore northwest Madagascar. The data will provide improved subsurface imaging of the large Sifaka prospect and will potentially mature additional prospects in the Ampasindava block to drill-ready status. Sterling Energy (UK) holds a 30% interest in the Ampasindava production sharing contract, which is operated by ExxonMobil Exploration and Production (Northern Madagascar) (70%). Asia Pacific Production began on the Liuhua 19-5 gas field in the Pearl River Mouth basin in the South China Sea. The field is expected to hit peak production of 29 MMcf/D this year. China National Offshore Oil Corporation (100%) is the operator. Drilling began on the YNG 3264 and the CHK 1177 development wells onshore in Myanmar.
Africa (Sub-Sahara) Mazarine Energy has started a two-well drilling campaign in the Zaafrane permit in central Tunisia. The first well, Cat-1, has been spudded and is targeting the Ordovician interval at a planned total depth of 3900 m. Mazarine (45%) is the operator with partners ETAP (50%) and MEDEX (5%). Asia Pacific Australia Pacific LNG has received its first gas from coal seam gas fields in the Surat basin. The gas is being carried to its liquefied natural gas (LNG) facility on Curtis Island, near Gladstone, Queensland, by a 530-km high-pressure gas pipeline, which was recently commissioned. With the arrival of gas, Australia Pacific can begin commissioning power generator facilities on the island. The company expects to deliver its first LNG in the middle of the year.
Calcium carbonate (CaCO3) scale formation in production wells and process systems is a well-known challenge in the oil and gas industry. Various strategies are selected to prevent scale formation (proactive, e.g. by scale inhibitors) or to remove scale when it has formed (reactive, e.g. by acid treatment), depending on the severity of the problem and the complexity of the production system. Lack of access for remedial actions may be a limiting factor in subsea and unmanned installations and scaling may represent a larger risk of production losses or system failures.
The scale management strategy and design of new wells during field development are based on thermodynamic calculations, kinetic studies and field observations. Experience has shown that wells with high temperature and high pressure drops are more prone to downhole calcium carbonate scaling.
Field experience has been collected and systemized based on operations of oil and gas-condensate fields in the North Sea and Norwegian Sea. The observations have been compared to thermodynamic calculations and aligned to kinetic modelling, defining the critical saturation ratio (
The Oseberg field in the North Sea is producing from oil and gas-condensate wells at various reservoir temperatures (98-128°C). The field comprises platform and subsea production systems and one unmanned wellhead platform. Seawater has been injected for pressure support in some areas, while gas injection or depletion are the driving forces in other segments. The CaCO3 scale potential and management strategy have been evaluated for new wells in a field life perspective. Risk of production losses and maximizing cost benefit are key selection criteria, and the variety of wells requires individual solutions. The paper discusses the need for downhole continuous injection of scale inhibitor, compared to batch scale inhibitor squeeze treatments and/or acid treatments. Guidelines for optimum operation of these wells to avoid scaling are presented.
The first well, Cat-1, has been spudded and is targeting the Ordovician interval at a planned total depth of 3900 m. Mazarine (45%) is the operator with partners ETAP (50%) and MEDEX (5%). Asia Pacific China National Offshore Oil Company (CNOOC) has made a natural gas discovery at its deepwater Lingshui 25-1 well, northeast of Ledong sag in the South China Sea's Qiongdongnan basin, where the average water depth is 980 m.
Digitalization and Artificial Intelligence have impacted the oil and gas industry. Drilling of wells, predictive maintenance and digital fields are examples for the use of these technologies. In hydrocarbon production forecasting, numerical reservoir models and "digital twins" of reservoirs have been used for decades. However, increasing computing power and Artificial Intelligence recently enabled oil and gas companies to generate "digital siblings" of reservoirs (model ensembles) covering the uncertainty range in static data (e.g. petrophysics, geological structure), dynamic data (e.g. oil or gas properties) and economics (Capital Expenditures, Operating Expenditures). Machine Learning and Artificial Intelligence are applied to condition the model ensembles to measured data and improve hydrocarbon production forecasting under uncertainty.
The model ensembles can be used for quantitative decision making under uncertainty. This allows companies to shorten the time for field (re-)development planning and to develop into learning organizations for decision making.
These developments require companies to change the way of working in hydrocarbon production forecasting and decision analysis. Additional skills need to be developed in companies to embrace digitalization. Data science - which is considered a key skill in digitalization - has not been identified as crucial in skills development of oil and gas companies in the past. However, for data driven decision making, advanced data analytics skills and data science skills are a pre-requisite. To overcome this skill gap, staff needs to be trained and graduates with data science and profound physical and chemical skills need to be hired.
Furthermore, skills development has to address the challenge of incorrect use of Machine Learning technologies and the risks of Artificial Intelligence leading to erroneous optimizations. In particular interpretability of AI needs to be covered in skills development.