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ABSTRACT The industry is facing significant challenges due to the recent downturn in oil prices, particularly for the development of tight reservoirs. It is more critical than ever to 1) identify the sweet spots with less uncertainty and 2) optimize the completion-design parameters. The overall objective of this study is to quantify and compare the effects of reservoir quality and completion intensity on well productivity. We developed a supervised fuzzy clustering (SFC) algorithm to rank reservoir quality and completion intensity, and analyze their relative impacts on wells' productivity. We collected reservoir properties and completion-design parameters of 1,784 horizontal oil and gas wells completed in the Western Canadian Sedimentary Basin. Then, we used SFC to classify 1) reservoir quality represented by porosity, hydrocarbon saturation, net pay thickness and initial reservoir pressure; and 2) completion-design intensity represented by proppant concentration, number of stages and injected water volume per stage. Finally, we investigated the relative impacts of reservoir quality and completion intensity on wells' productivity in terms of first year cumulative barrel of oil equivalent (BOE). The results show that in low-quality reservoirs, wells' productivity follows reservoir quality. However, in high-quality reservoirs, the role of completion-design becomes significant, and the productivity can be deterred by inefficient completion design. The results suggest that in low-quality reservoirs, the productivity can be enhanced with less intense completion design, while in high-quality reservoirs, a more intense completion significantly enhances the productivity. Keywords Reservoir quality; completion intensity; supervised fuzzy clustering, approximate reasoning,tight reservoirs development
The complete paper describes the operator's first implementation of fishbone stimulation technology. A multidisciplinary team analyzed the operational procedures, conducted risk assessments and logistical studies, and established contingency plans, technical requirements, and technical limitations. The deployment of the equipment and the production results were a success, overcoming hazard risks and uncertainties and closing gaps from previous, partially effective applications. According to the authors, fishbone stimulation technology will help increase productivity in a well too risky to be hydraulically fractured and beyond the reach of coiled tubing. As the industry seeks dynamic changes and novel ideas to increase the productivity of tight, thin reservoirs, fisbone stimulation represents a lower-risk and -cost solution to ensure deep connectivity with the reservoir in situations in which traditional conventional stimulation practices have reached their potential boundaries without achieving crude recovery objectives.
Abstract As a resourced based economy, Malaysia relies heavily on the energy oil, and gas industry - a critical sector contributing to the economic growth of the Malaysian economy; which makes up in the range of 20% - 25% of the total gross domestic product (GDP) of Malaysia as of 2017. No analysts can properly predict prices of the future, with the highs and lows of crude and natural gas and renewables as the fuel of the future and are perhaps new way of things. This "new normal" in which countries, including Malaysia, must learn to adapt in a more agile manner to the "new way of work" of increased productivity and efficiency (de Graauw, McCreery, & Murphy, 2015). In adapting to the new normal, measures of increased productivity must continue to be pushed forward and implemented. Energy companies and services provider still need to continue with exploration and development (E&P) operations and activities to meet long term strategic objectives and demands of the nation, in line with the aspirations of the national oil company, however, it needs to add more value to every dollar spent as margins have continued to shrink and reduce profit margins of energy producers. This is where Digital Transformation comes into play and the urgency for implementation has gone from novelty solutions to critical business survival. Changing industry trends such as Industrial Revolution 4.0 have made it more prevalent than ever to make better use of capital at a time when productivity is essential. At the same time, the industry needs to continue to explore and develop to meet long-term demands, which continues to grow albeit slower than before.
Wu, Tao (CNPC Chuanqing Drilling Engineering Co.LTD) | Fang, Hanzhi (Yangtze University) | Sun, Hu (CNPC Chuanqing Drilling Engineering Co.LTD) | Zhang, Feifei (Yangtze University) | Wang, Xi (Yangtze University) | Wang, Yidi (Yangtze University) | Li, Siyang (Yangtze University)
Abstract Unconventional reservoirs such as shale and tight sandstones that with ultra-low permeability, are becoming increasingly significant in global energy structures (Pejman T, et al., 2017). For these reservoirs, successful hydraulic fracturing is the key to extract the hydrocarbon resources efficiently and economically. However, the intrinsic mechanisms of fracturing growth in the tight formations are still unclear. In practice, fracturing design mainly depends on hypothetical models and previous experience, which leads to difficulties in evaluating the performance of the fracturing jobs. Therefore, an improved method to optimize parameters for fracturing is necessary and beneficial to the industry. In this paper, a data-driven approach is used to evaluate the factors that dominate the production rate from tight sandstone formation in Changqing Field which is the largest oil field in China. In the model, the input parameters are classified into two categories: controllable parameters (e.g. stage numbers, fracturing fluid volume) and uncontrollable parameters (e.g. formation properties), and the output parameter is the accumulated oil production of the wells. Data for more than 100 wells from different formations and zones in Changqing Field are collected for this study. First, a stepwise data mining method is used to identify the correlations between the target parameter and all the available input parameters. Then, a machine learning model is developed to predict the well productivity for a given set of input parameters accurately. The model is validated by using separate data-sets from the same field. An optimize algorithm is combined with the data-driven model to maximize the cumulative oil production for wells by tuning the controllable parameters, which provides the optimized fracturing design. By using the developed model, low productivity wells are identified and new fracturing designs are recommended to improve the well productivity. This paper is useful for understanding the effects of designed fracturing parameters on well productivity in Changqing Oilfield. Furthermore, it can be extended to other unconventional oil fields by training the model with according data sets. The method helps operators to select more effective parameters for fracturing design, and therefore reduce the operation costs for fracturing and improve the oil and gas production.
Mohsin, Adel (College of Science and Engineering, Hamad Bin Khalifa University) | Abd, Abdul Salam (College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad (College of Science and Engineering, Hamad Bin Khalifa University)
Abstract Condensate banking in natural gas reservoirs can hinder the productivity of production wells dramatically due to the multiphase flow behaviour around the wellbore. This phenomenon takes place when the reservoir pressure drops below the dew point pressure. In this work, we model this occurrence and investigate how the injection of CO2 can enhance the well productivity using novel discretization and linearization schemes such as mimetic finite difference and operator-based linearization from an in-house built compositional reservoir simulator. The injection of CO2 as an enhanced recovery technique is chosen to assess its value as a potential remedy to reduce carbon emissions associated with natural gas production. First, we model a base case with a single producer where we show the deposition of condensate banking around the well and the decline of pressure and production with time. In another case, we inject CO2 into the reservoir as an enhanced gas recovery mechanism. In both cases, we use fully tensor permeability and unstructured tetrahedral grids using mimetic finite difference (MFD) method. The results of the simulation show that the gas and condensate production rates drop after a certain production plateau, specifically the drop in the condensate rate by up to 46%. The introduction of a CO2 injector yields a positive impact on the productivity and pressure decline of the well, delaying the plateau by up to 1.5 years. It also improves the productivity index by above 35% on both the gas and condensate performance, thus reducing production rate loss on both gas and condensate by over 8% and the pressure, while in terms of pressure and drawdown, an improvement of 2.9 to 19.6% is observed per year.
Fines migration is a recognized source of formation damage in some production wells, particularly in sandstones. Direct evidence of fines-induced formation damage in production wells is often difficult to come by. Although most other forms of formation damage have obvious indicators of the problem, the field symptoms of fines migration are much more subtle. Indirect evidence such as declining productivity over a period of several weeks or months is the most common symptom. This reduction in productivity can usually be reversed by mud-acid treatments.
Roostaei, Morteza (RGL Reservoir Management Inc.) | Soroush, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Mohammadtabar, Farshad (RGL Reservoir Management Inc.) | Mohammadtabar, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Hosseini, Seyed Abolhassan (University of Alberta and RGL Reservoir Management Inc.) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Sadrzadeh, Mohtada (University of Alberta) | Ghalambor, Ali (Oil Center Research International) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.)
Summary The historical challenges and high failure rate of using standalone screen in cased and perforated wellbores pushed several operators to consider cased-hole gravel packing or frac packing as the preferred completion. Despite the reliability of these options, they are more expensive than a standalone screen completion. In this paper, we employ a combined physical laboratory testing and computational fluid dynamics (CFD) for laboratory scale and field scale to assess the potential use of the standalone screen in completing the cased and perforated wells. The aim is to design a fit-to-purpose sand control method in cased and perforated wells and provide guidelines in perforation strategy and investigate screen and perforation characteristics. More specifically, the simultaneous effect of screen and perforation parameters, near wellbore conditions on pressure distribution and pressure drop are investigated in detail. A common mistake in completion operation is to separately focus on the design of the screen based on the reservoir sand print and design of the perforation. If sand control is deemed to be required, the perforation strategy and design must go hand in hand with sand control design. Several experiments and simulation models were designed to better understand the effect of perforation density, the fill-up of the annular gap between the casing and screen, perforation collapse, and formation and perforation damage on pressure drop. The experiments consisted of a series of step-rate tests to investigate the role of fluid rate on pressure drop and sand production. There is a critical rate at which the sand filling up the annular gap will fluidize. Both test results and CFD simulation scenarios are comparatively capable to establish the relation between wellbore pressure drop and perforation parameters and determine the optimized design. The results of this study highlight the workflow to optimize the standalone screen design for the application in cased and perforated completions. The proper design of standalone screen and perforation parameters allows maintaining cost-effective well productivity. Results of this work could be used for choosing the proper sand control and perforation strategy.
Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.
If the problem is formation damage, then matrix acidizing may be an appropriate treatment to restore production. This page discusses ways to evaluate whether a well is a good candidate for acidizing. This plugging can be either mechanical or chemical. Mechanical plugging is caused by either introduction of suspended solids in a completion or workover fluid, or dispersion of in-situ fines by incompatible fluids and/or high interstitial velocities. Chemical plugging is caused by mixing incompatible fluids that precipitate solids.
Kidogawa, Ryosuke (INPEX Corporation) | Yoshida, Nozomu (INPEX Corporation) | Fuse, Kei (INPEX Corporation) | Morimoto, Yuta (INPEX Corporation) | Takatsu, Kyoichi (INPEX Corporation) | Yamamura, Keisuke (INPEX Corporation)
Summary Productivity of multistage‐fractured gas wells is possibly degraded by conductivity impairments and non‐Darcy flow during long‐term production. Such degradations are pronounced by flow convergence to short perforated intervals, while it is challenging to identify degraded stages for remediation. Moreover, remedial actions can be expensive under a high‐pressure/high‐temperature (HP/HT) environment. A field case demonstrates successful application of reperforation as a cost‐effective way to mitigate the flow convergence by prioritizing targets with multirate production‐logging (PL) results. This work presents theoretical investigations using numerical simulations and field execution of reperforation for a well with six‐stage fracturing treatments in a HP/HT volcanic gas reservoir onshore Japan. Apparent conductivity reduction was suspected during more than 15 years of production, and it was pronounced by non‐Darcy flow effects associated with flow convergence to short perforated intervals. Multirate PL was used to identify impaired stages by quantifying the inflow‐performance relationship (IPR) of each stage under transient flow‐after‐flow (FAF) testing. The impaired stages were reperforated, adding perforation intervals with wireline‐conveyed perforators. Pressure‐buildup (PBU) tests before and after the job and post‐job PL were used to validate productivity improvements. Target zones for reperforations were identified and prioritized with results of the multirate PL conducted. The stage IPRs were drawn, and relatively large non‐Darcy effects were identified in three stages by shapes of the IPRs and/or decreasing inflow contributions as the surface rate increased. Also, a temperature log showed steep temperature change at the bottom of the fourth stage; the fracture might propagate below the perforated interval. Ranges of production increment were estimated using a numerical model calibrated against the estimated stage IPRs. The estimated increment was in the range of 15 to 30% with the planned reperforation program, while its magnitude depended on the connection between new perforations and existing fractures. Afterward, the reperforation job was performed and the gas rate was confirmed to be increased by 26% with the same wellhead pressure after 1 month of production. The post‐job PL was conducted 3 months after the reperforation. The well IPR was improved, implying reduction of the non‐Darcy effects. Results of PBU tests also indicated reduction of skin factor. The stage IPRs were redrawn with the post‐job PL, and they suggested clear improvements in two stages where screenout occurred during fracturing treatments and a stage where significant non‐Darcy effect was suspected. The workflow and strategy in this paper can be applied for productivity restoration in a cost‐effective way to multistage‐fractured gas wells with short perforated intervals and impaired apparent conductivity during long‐term production. Especially, the interpreted results suggested effectiveness of the proposed approach for productivity improvement in stages where screenout occurs during fracturing treatments. Moreover, lessons learned on the importance of careful test designs for PL were discussed because they are keys for success.