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Abstract Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). In this study, we present a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, we show that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements.
Potapenko, Dmitriy Ivanovich (Member) | Hart, Timothy Brian (Fremont Petroleum Corporation) | Waters, George Alan (Member) | Lewis, Richard E. (Member) | Utter, Robert J. (New Ventures Energy Consulting) | Brown, J. Ernest (Member) | Goudy, Guy Thomas (Formerly Fremont Petroleum Corporation) | Jelsma, Henk H (Radial Drilling Services, Inc.)
Abstract This paper describes the first application of a novel reservoir-stimulation methodology that combines oriented extended perforation tunnels of lengths up to 300 feet with specially designed hydraulic fracturing operations in the Niobrara Formation in the Florence Field in Colorado. The technology was extensively tested in two vertical wells completed with two and five pairs of the extended perforation tunnels respectively. Extended perforation tunnels were jetted using radial drilling technique with the tools deployed using micro coil tubing. The jetting operation on each well was followed by a fracture stimulation treatment. The use of radial drilling technology to create extended perforation tunnels for the vertical wells offered a cost-effective way to significantly increase the reservoir contact area of the wellbore, making it similar to that of horizontal wells in the area. The engineered fracture treatments were performed at low treating pressures, and low proppant and fluid volumes. The stabilized production rates of both project vertical wells included in this technology test exceeded expectations and are comparable to the stabilized production rate of the offset horizontal well that was completed in the same zone with significantly higher volumes of proppant and fluid. The initial evaluation of the completion efficiency of this novel reservoir stimulation technology showed that its deployment delivered an improved stabilized production rate to cost ratio for the second vertical well, compared to the reference horizontal well. Based on the test results from the two wells, we conclude that the proposed reservoir stimulation methodology leads to substantial improvements in well production performance compared to traditional reservoir stimulation methods. Both the applied cost-effective approach for increasing the reservoir contact and the significantly lower resource intensity required for the hydraulic fracturing treatment further improve the economic benefits of this methodology. This novel reservoir stimulation methodology opens the way for reconsidering well completion practices in the Niobrara Formation and holds significant potential for improving the hydrocarbon production economics in the Florence Field.
Zhang, Kai (China University of Petroleum (Corresponding author) | Wang, Yanzhong (email: email@example.com)) | Li, Guoxin (China University of Petroleum) | Ma, Xiaopeng (PetroChina) | Cui, Shiti (China University of Petroleum) | Luo, Qin (Southwest Petroleum University) | Wang, Jian (Exploration and Development Research Institute of PetroChina Tarim Oilfield Company) | Yang, Yongfei (China University of Petroleum) | Yao, Jun (China University of Petroleum)
Summary We are interested in the development of surrogate models for the prediction of field saturations using a fully convolutional encoder/decoder network based on the dense convolutional network (DenseNet; Huang et al. 2017), similar to the approaches used for image/image-regression tasks in deep learning. In the surrogate model, the encoder network automatically extracts the multiscale features from the raw input data, and the decoder network then uses these data to recover the input image resolution at the output of the model. The input of multiple influencing factors is considered to make our surrogate model more consistent with the physical laws, which has achieved good results in the prediction of output fields in our experiments. Various reservoir parameters including the static reservoir properties (i.e., permeability field) and dynamic reservoir properties (i.e., well placement) are used as input features, and the water-saturation distributions in different periods are taken as the output. Compared with traditional numerical reservoir simulation, which has a high computational cost and is time consuming, not only does it present the same precision, but it costs less time. At the same time, it can also be used for production optimization and history matching.
Zhao, Qingqi (The University of Tulsa) | Zhu, Jianjun (China University of Petroleum-Beijing (Corresponding author) | Cao, Guangqiang (email: firstname.lastname@example.org)) | Zhu, Haiwen (PetroChina Research Institute of Petroleum Exploration & Development) | Zhang, Hong-Quan (The University of Tulsa (Corresponding author)
Summary As an economical and efficient artificial lift method, plunger lift can be used to unload the accumulated liquids from the bottom of gas wells, which helps lower the bottomhole pressure, resulting in higher gas production rate. However, the transient flow behavior of the plunger-lift-aided production system is still not well understood due to the lack of a reliable and accurate prediction model. In this study, a transient mechanistic model is developed to simulate the comprehensive dynamic process of a plunger-lift system that is cyclically paced by a surface control valve. Starting from the Gasbarri and Wiggins (2001) dynamic plunger-lift model, four stages in the cyclic movement of a plunger can be identified and calculated using a set of specific governing equations. Considering the gas flows with a plunger in the tubing, the model can calculate the instant velocities of the plunger during its rising and falling movement. The classical inflow performance relationship (IPR) is employed as the reservoir model to obtain the fluid flow rates from the reservoir to the wellbore. The proposed new model can capture the essential parameters of plunger-lift cycles, including plunger velocity/acceleration, tubing/casing pressure, production rates, etc. Compared to previous models, the predicted rising and falling speeds of the plunger are improved. The hydrocarbon mixture properties in the gas well are computed by a compositional model in this study, which provides more accurate and reasonable predictions of tubing and casing pressure. Several parametric studies are presented in the paper. These studies will help to understand the influence of different parameters on the process of plunger lift. An appropriate combination of casing and tubing pressure should be taken into consideration. A reservoir coefficient term is introduced and defined. A larger reservoir coefficient will improve the ultimate profitability of the well by increasing the production rate at the beginning and accelerate the depletion of gas wells. If the gas/liquid ratio (GLR) is too low, liquid loading may be triggered. The parametric study shows that an adequate GLR is necessary for reliable plunger-liftperformance.
Zaitoun, Alain (Poweltec) | Templier, Arnaud (Poweltec) | Bouillot, Jerome (Poweltec) | Salehi, Nazanin (Poweltec) | Wijaya, Budi Rivai (Pertamina PHE ONWJ) | Wijaya, Agung Arief (Pertamina PHE ONWJ) | Witjaksono, Arief (Pentraco) | Kurniadi, Wery (Pentraco)
Abstract Many fields in South East Asia are suffering from sand production problems due to sensitive sandstone formation. Sand production increases with time and increasing water production. The production of sand induces loss of production, due to sand accumulation in the wellbore, and heavy operational costs such as frequent sand cleaning jobs, pump replacements, replacement of surface and downhole equipment, etc. An original sand control technology consisting of polymers injection and already deployed in gas wells, has been successfully tested in an offshore oil well. The technology utilizes polymers having a natural tendency to coat the surface of the pores by a thin gel-like film of around 1 µm. Contrary to the use of resins which aim at creating a solid around the wellbore, the polymer system maintains the center of the pores fully open for fluid flow, thus preserving oil or gas permeability while often reducing water permeability (a property known as RPM for Relative Permeability Modification). The advantage of such system is that the product can be injected in the bullhead mode and often, a reduction of water production is observed along the drop in sand production. In gas wells, the treatment lasts around 4 years and can be renewed periodically. A lab work was undertaken to screen out a polymer product well suited to actual reservoir conditions. We conducted bulk tests to evaluate product interaction on reservoir sand samples, and corefloods to evaluate in-situ performances. Treatment volume and concentration were determined after lab test. One of "Oil Well" candidate is located in Arjuna Field, offshore Indonesia. Downhole conditions are: Temperature = 178°F, salinity = 18000 ppmTDS, permeability = 140-300mD, two perforated intervals with total thickness of 67ft (ft-MD) with 38 ft Average Netpay Thickness, production rate = 800 bfpd. The well is under gas lift and needed to be cleaned out every 3 months because of sand accumulation. Polymer treatment was performed in two stages (bottom, then upper interval). A total volume of 150 m3 of polymer solution was pumped. Immediately after treatment, sand cut dropped from 1% to almost 0%. This enabled increasing the drawdown from 32/64’’ choke to 40/64’’, keeping the production sand free and sustained with time. This field test confirms the feasibility of the original sand control polymer technology both in gas wells and in oil wells, which opens high possibilities in the future.
Abstract Run-to-end (hereafter referred to "RTE") is a fit-for-purpose approach to manage late field life assets for realization of full potential through safe, reliable and cost effective operation by maximizing value at the end of economic life while complying to minimum technical standards through ALARP demonstration. RTE provides an overview of the multiple processes which shall be adopted and customized to the business needs of the intended facilities with the aim to minimize value leakage and ensuring safety until facility's cease of production prior to relinquishment or decommissioning. This RTE philosophy is to be applied to facilities that are within 5 years of its end of economic life so that value leakage can be minimized within the tolerable risk. The RTE provides an overview of development of case for change, guided process for the Operation & Maintenance philosophy changes and demonstration of risks mitigation & governance assurance. The safety risk of the facility shall be assessed and monitored through continuous ALARP demonstration. If the facility is deemed to be either no longer safe through ALARP or can no longer maintain a positive cash flow position, it is recommended that the facility to cease production operations and proceed with relinquishment or decommissioning activities. It has been implemented in one of late field life and resulting to 30% reduction of OPEX.
Tang, Catherine, Ye (Petronas Carigali Sdn Bhd) | Tan, Kok Liang (Petronas Carigali Sdn Bhd) | Riyanto, Latief (Petronas Carigali Sdn Bhd) | Tusimin, Fuziana (Petronas Carigali Sdn Bhd) | Sapian, Nik Fazril (Petronas Carigali Sdn Bhd) | Sharim, Noor Azima (Petronas Carigali Sdn Bhd)
Abstract Well#1 was completed as horizontal oil producer with Openhole Stand-Alone Sandscreens (OHSAS) across a thin reservoir with average thickness of 20ft in Field B. The first Autonomous Inflow Control Device (AICD) in PETRONAS was installed to ensure balanced contribution across horizontal zones with permeability contrasts and to prevent early water and gas breakthrough. Integrated real-time reservoir mapping-while-drilling technology for well placement optimization combined with industry-leading inflow control simulator for AICD placement were opted. The early well tests post drilling showed promising results with production rate doubled the expected rate with no sand production, low water cut and lower Gas to Oil Ratio (GOR). Reservoir Management Plan (RMP) for this oil rim requires continuous gas injection into gas cap and water injection into aquifer. However, due to low gas injection uptime caused by prolonged injection facilities constraints, the well's watercut continued to increase steadily from 0% to 80% within a year of production despite prudent surveillance and controlling of production during injector's downtime. After the gas injection performance has improved, the well was beaned up as part of oil rim management for withdrawal balancing. Unfortunately, a month later, the production rate showed a sudden spike with significantly low wellhead pressure, followed by hairline leak on its choke valve and leak at Crude Oil Transfer Pump (COTP) recycle line. Sand analysis by particle size distribution (PSD) confirmed OHSAS failure, while the high gas rate from well test results confirmed AICD failure. A multidisciplinary investigation team was immediately formed to determine the root cause of the failure event. Root Cause Failure Analysis (RCFA) method was opted to determine the causes of failures, including the reanalyzing of the OHSAS and AICD completion design. The well operating strategy was also reviewed thoroughly by utilizing the well parameters trending provided in the Exceptional Based Surveillance (EBS) Process Information (PI) ProcessBook. Thorough RCFA concluded that frequent platform interruptions and improper well start-up practices have created abrupt pressure changes in the wellbore, which has likely destabilized the natural sand pack around the OHSAS and created frequent burst of sand influx across AICDs. The operating of a high gas-oil ratio (GOR) and high watercut sand prone well without pre-determined AICD sand erosion toleration envelope have also likely contributed to the failure of AICDs. The delay in detection of OHSAS failure in Well#1 due to ineffective sand monitoring method thus resulted in severe sand production which caused severe leak at its choke valve and COTP recycle line.
Jia, Ying (Exploration and Production Research Institute, Sinopec) | Shi, Yunqing (Exploration and Production Research Institute, Sinopec) | Yan, Jin (Exploration and Production Research Institute, Sinopec)
Abstract Tight gas reservoirs are widely distributed in China, which occupies one-third of the total resources of natural gas. The typical development method is under primary depletion. However, the recovery of tight gas is only around 20%. It is necessary to explore a new technique to improve tight gas recovery. Injecting CO2 into tight gas reservoirs is a novel trial to enhance gas recovery. The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery of tight gas reservoir. Taken DND tight sandstone gas reservoir in North China as an example, 34 wells of DK13 wellblock were chosen as CO2 Enhanced gas recovery pilot area with 10-year production history. Six injection scenarios were studied. Numerical simulation indicated that the recovery of the gas reservoir of DK13 well area was improved by 8-9.5 percent when CO2 content of producers reaches 10 percent. The annual CO2 Storage would be 62 million cubic meters (110 thousand tons) and the total CO2 storage would be around 800million cubic meters (1.5 million tons). After the environmental parameter evaluation of injectors and producers, the anticorrosion schemes were put forward and the feasibility evaluation and schemes of facilities were presented. The analysis results indicated that DK13 wellblock was suitable for CO2 enhanced gas recovery no matter geologic condition, injection & production technology and facilities. However, under the current economic conditions, DK13 wellblock was not suitable for CO2to enhance gas recovery. However, if gas price rise or low carbon strategy implement, the pilot test could be carried out. In brief, CO2 could be an attractive option to successfully displace natural gas and decrease CO2 emissions, which is a promising technology for reducing greenhouse gas emission and increasing the ultimate gas recovery of tight gas reservoirs. This economic analysis, along with reservoir simulation and laboratory studies that suggest the technical feasibility of CSEGR, demonstrates that CSEGR can be feasible and that a field pilot study of the process should be undertaken to test the concept further.
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.
A wellhead choke controls the surface pressure and production rate from a well. Chokes usually are selected so that fluctuations in the line pressure downstream of the choke have no effect on the production rate. This requires that flow through the choke be at critical flow conditions. Under critical flow conditions, the flow rate is a function of the upstream or tubing pressure only. For this condition to occur, the downstream pressure must be approximately 0.55 or less of the tubing pressure.