This study presents a numerical modeling of a sodium silicate gel system (inorganic gel) to mitigate the problem of excess water production, which is promoted by high heterogeneity and/or an adverse mobility ratio. A numerical model of six layers was represented by one quarter of five spot pattern with two thief zones. CMG-STARS simulator was used that has the capabilities of modeling different parameters. The gelation process of this gel system was initiated by lowering the gelant's pH, and then the reaction process proceeded, which is dependent on temperature, concentration of the reactant, and other factors. An order of reaction of each component was determined and the stoichiometric coefficients of the reactants and product were specified. The purpose of this study is to develop a thorough understanding of the effects of different important parameters on the polymerization of a sodium silicate gel system.
This study was started by selecting the optimum gridblock number that represents the model. A sensitivity analysis showed that the fewer the number of gridblocks, the better the performance of the gel system. This model was then selected as a basis for other comparisons. Different scenarios were run and compared. The results showed that the gel system performed better in the injection well compared to the production well. In addition, the treatment was more efficient when performed simultaneously in injection and production wells. Placement technology was among the parameters that affected the success of the treatment; therefore, zonal isolation and dual injection were better than bullhead injection. Lower activator concentration is more preferable for deep placement. Pre-flushing the reservoir to condition the targeted zones for sodium silicate injection was necessary to achieve a higher recovery factor. Moreover, different parameters such as adsorption, mixing sodium silicate with different polymer solutions, effects of temperature and activation energy, effects of shut-in period after the treatment, and effects of reservoir wettability were investigated. The obtained results were valuable, which lead to apply a sodium silicate gel successfully in a heterogeneous reservoir.
Yang, Zhaopeng (PetroChina Research Institute of Petroleum Exploration&Development) | Li, Xingmin (PetroChina Research Institute of Petroleum Exploration&Development) | Chen, Heping (PetroChina Research Institute of Petroleum Exploration&Development) | Liu, Zhangcong (PetroChina Research Institute of Petroleum Exploration&Development) | Luo, Yanyan (PetroChina Research Institute of Petroleum Exploration&Development) | Fang, Lichun (PetroChina Research Institute of Petroleum Exploration&Development)
The foamy extra-heavy oil reservoirs in the eastern Orinoco Belt, Venezuela with high initial dissolved gas oil ratio and flow ability in situ, have been exploited by the Cold Heavy Oil Production (CHOP) method, with recovery of only 8%-12% OOIP. SAGD has proved to be one of commercially active post-CHOP processes. Whereas during the SAGD process the dissolved gas as non-condensable gas accumulated at the edges of the steam chamber causes a resistance to heat transfer between steam and oil, thus slowing down growth of the steam chamber and oil recovery. Therefore a novel SAGD process using alternate imbalance operating-pressure (AIOP-SAGD) is studied for the purpose of improving foamy oil SAGD performance.
The novel SAGD process involves multi SAGD well pairs, and with the growth of steam chambers, a significant pressure gradient is deliberately created between two steam injection wells. Moreover the higher and lower operation pressure of the two injection wells is periodically alternate. In this work, the potential evaluation and optimization of foamy oil AIOP-SAGD are studied, through extensive simulations utilizing a sector model, which is from a sector with representative oil and reservoir characteristics of Eastern Orinoco Belt, considering the mechanism of foamy oil and thermal recovery.
Simulation results indicate that the AIOP-SAGD process shows significant improvement in oil recovery, at least 10% higher than traditional SAGD. The mechanism includes two aspects: firstly the pressure gradient between two adjacent SAGD well pairs brings a sweep of dissolved gas from steam chambers; secondly, based on the flow ability of foamy extra-heavy oil, the pressure gradient helps to exploit oil between two SAGD pairs which is typically difficult to be recovered with conventional SAGD. The optimization of operating parameters shows that the optimal start time of AIOP-SAGD is when the oil rate of SAGD reaches the peak and the steam chamber extends to the top of the reservoir. High steam quality helps improve the performance of AIOP-SAGD. Moreover the parameters of alternate time, imbalance time, imbalance pressure difference were optimized.
Bao, Yu (Research Institute of Petroleum Exploration & Development, CNPC) | He, Liangchen (Liaohe Oilfield Company Ltd, Petrochina) | Lv, Xue (Sino-Pipeline International Company Ltd.) | Shen, Yang (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Xingmin (Research Institute of Petroleum Exploration & Development, CNPC) | Liu, Zhangcong (Research Institute of Petroleum Exploration & Development, CNPC) | Yang, Zhaopeng (Research Institute of Petroleum Exploration & Development, CNPC)
The Orinoco heavy oil belt in Venezuela is one of the largest extra-heavy oil resources in the world. It has become a major goal for the unconventional oil exploitation in these years. Now, the most common production method is to use the horizontal well cold production without sand. It is an economic and commercial process, and with the reservoir of this area have high initial gas to oil ratio (GOR), porosity and permeability with unconsolidated sand. However, after several years' production, the oil rate draws down quickly caused by the reservoir pressure drops; the key challenge of cold production is that the recovery factor (RF) tends to be only between 8% and 12%, implying that the majority of the oil remains in the oil formation. It is necessary to develop viable recovery processes as a follow-up process for cold production. Generally, steam based recovery method was widely used as a follow-up process for cold production. In this paper, steam fracturing (dilation) Cyclic Steam Stimulation (CSS) operation and Non steam fracturing (No dilation) CSS operation by using reservoir simulator is examined for a post cold production in extra heavy oil reservoir, in order to analyze the performance of the oil rate, cumulative steam-to-oil ratio (cSOR), steam depletion zone, greenhouse gas emission and some necessary parameters.
The key component of the steam fracturing (dilation) is the ability to inject high temperature and pressure steam into the formation to fracture the reservoir rock which in turn raises the rock permeability and mobilized the oil by lowering the visocisity. To compare the results of the dilation and no dilation CSS operation, this study reveal that due to the steam is injected into the reservoir by using the same cumulative cold water equivalent (CWE), the steam condensate; pressurized by steam vapour, fracture the formation. Dilation operation achieves higher oil rate, lower cSOR. The result also show that fraturing (dilation) of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below the case where No dilation operation ouccurs.
Particle size, shape and mineralogy are considered as primary characteristics of sand and sandstone. Several techniques have been developed for the particle size and shape analysis of unconsolidated sands. However, few of these techniques can be used for sandstones. Most particle size measurement techniques provide a spherical equivalent of the particle size and neglect the particle shape. Although several techniques have been developed for the particle size and shape analysis of the unconsolidated sands, these techniques could not be used for the size and shape variation analysis of consolidated or semi-consolidated sandstone.
Recently, X-ray micro CT scanning technique has been used for the evaluation of petrophysical properties of sandstones. This paper presents a workflow for the measurement of particle size and shape of sandstones. This research utilized X-ray micro CT scans for 2-dimensional particle shape measurements including Sphericity, Convexity, Aspect Ratio and Feret diameters. The methodology presented in this paper is the first step toward assessing the particle shape and size variation of sandstones for use in such applications as sand control design.
Image-J, an Open-source software, was used to process and filter the X-ray raw images. A new tool was developed to measure the shape factors (i.e. Sphericity, Aspect Ratio and Convexity) and size variations. A series of images from different sandstones were analyzed and compared to their lab measurements. The image calculated porosity and permeability showed some degree of deviation from the lab measured porosity and permeabilities.
This paper presents a new workflow to measure the particle size and shape for the sand control design in sandstone reservoirs. With a larger database it is possible to develop a correlation to calculate rock properties from image size analysis technique and correct them for the shape variation. The next step will be to measure the 3D size and shape from the image analysis and compare to the shape and size analysis from dynamic image analysis.
Sand-slug fracturing has been the main fracturing pumping mode due to the tightness of shale. This mode makes it easier to inject proppants. However, it may cause poor connectivity in the middle brittle formation due to the discontinuous propping. This paper describes an attempt to fracture the unconventional shales with conventional sand-ramp fracturing pumping mode. The results show that good effect is achieved compared with the sand-slug fracturing mode used in the adjacent wells.
Shale reservoir reconstruction has large construction displacement and high pressure, and it adopts fracturing technology of slickwater and linear glue
The Sand-ramp modes using less fluid and higher sand content
Based on the understandings on geological characteristics and formation property, the sand-ramp fracturing pumping mode was designed. Two of six wells in the pad were selected to apply this mode. To maximize the stimulated reservoir volume, slickwater accounted for 40% to 60% of the total injected fluids. 100-mesh quartz sands were pumped in priority to improve the complexity of fracture. Then, the 40-70 mesh ceramsites was pumped with crosslinked gel to support the primary, secondary and natural fractures. The pumping rate is 12-13 cubic meters per minute and no acid is used throughout the whole pumping process.
The maximum proppant concentration of sand-ramp reached to 480 kilogram per cubic meters, which was much higher than that of sand-slugs. As a result, good propped fractures were obtained. Since no fluid sweep was used after the sand-slug, the average fluid injection per stage is declined by 27%, but the average sand injection volume was increased by 17%, which significantly reduced the cost and the possible influence to environment. With the sand-ramp mode, the highest test production of the block was up to 278500 cubic meters per day. This well produced 35 million cubic meters of shale gas in 270 days.
The practicability of the sand-ramp pumping mode used in unconventional shales is proven to be positive, especially in the formation with high horizontal stress difference. However, the development result needs to be continuously studied.
Wang, Chunpeng (PetroChina Research Institute of Petroleum Exploration & Development) | Cui, Weixiang (PetroChina Research Institute of Petroleum Exploration & Development) | Zhang, Hewen (PetroChina Research Institute of Petroleum Exploration & Development) | Qiu, Xiaohui (PetroChina Research Institute of Petroleum Exploration & Development) | Liu, Yuting (PetroChina Research Institute of Petroleum Exploration & Development)
In view of tight oil reservoirs with no natural productivity (tight sandstone and carbonate reservoirs with matrix permeability under overburden pressure of no more than 0.2mD (pore permeability less than 2mD)), a nanometer high efficient oil washing agent has been developed by combining nano-drop, high efficient oil washing surfactant and wettability reversal means, which can turn the disadvantage of the small pores and throats into advantage and realize fracturing effect enhancement by making use of the spontaneous imbibition.
For the tight oil reservoir, large scale and high pumping rate multi-stage fracturing in horizontal wells and fracture diversion technique are recommended to smash the reservoirto create a fracture network of natural fractures and artificial fractures for oil and gas flow. The aim is to increase reservoir stimulation volume and the artificial fracture area. Meanwhile, nanometer high efficient oil washing agent is added in the fracturing fluid. By changing rock wettability, the oil-wet interface is turned water-wet, and the capillary force is changed from imbibition resistance to imbibition drive, boosting spontaneous imbibition. Therefore, the biobased solvent and surfactant can work in synergy to separate the oil film from pore and throat surface, realizing displacement of oil by water. Experimental data shows the application the nanometer oil displacement agent can enhance the oil displacement efficiency of core by12%. After fracturing, the well should be shut down for some time. The shut-down time should take the reservoir pressure and temperature, pore structure and connectivity and the imbibition capacity of the fracturing fluid etc into account, and can be worked out by spontaneous imbibition experiment and NMR etc to guide field operation.
This technology has been used 10 well times in tight oil reservoirs in western China, including 3 well times of key exploration well stimulation, and 7 well times of old well repeated fracturing, all the treatments have achieved good effect. Among them, one well worth special note, this well had no production before fracturing, but obtained a high production of 42t a day after fracturing. During the shutdown of well, the fracturing fluid in the artificial fracture network can contact fully with micro-pores in the matrix and displace the oil in them through imbibition to the fracture system, then the oil can flow along the fracture network to the well bottom.
The high efficient imbibition fracturing technology for tight oil reservoir is a revolution in fracturing. With fracturing fluid system and well shutdown different from traditional fracturing, this technology can enhance fracturing effect and more importantly oil recovery. This paper has great guidance and reference significance for engineers and researchers engaged in tight oil development.
The objective of this Technical Paper is to show the experiences and challenges in the design and execution of an extended reach well in unconsolidated sands carried out by Pluspetrol Bolivia Corporation in the Tacobo-Curiche Area. Due to surface obstacles (bed of the Rio Grande river) was proposed the drilling of a directional well which trajectory had to pass through two objectives: 1570 m Horizontal Displacement (HD) at 770 mTVD and 2345 mHD at 1171 mTVD, with the following conditions: 1st.- unconsolidated sands, 2nd.- channel of the river and 3rd.- superficiality of the objectives. The main objectives set for this project were: 1. Reach the targets in the required position.
Matrix acidizing is a remedial well stimulation that done to overcome formation damage near wellbore or improve the permeability. Although acidizing treatments are proven and abundant there is still inherit from formation damage when pumped. Acid-induced asphaltene sludging is becoming an increasing cause of oil well stimulation Failure.
The objective of the paper is to evaluate the performance of coconut oil as a bio-oil dispersant against commercial dispersants in preventing asphaltene sludge while acidizing carbonate cores with 15 wt.% HCl and a chelating agent. A Kuwaiti crude oil was used in this study has an API of 38° and 2% asphaltene content. The crude oil was characterized by a variety of analytical techniques including total acid and base numbers (TAN, TBN), saturates, aromatics, resins and asphaltene analysis (SARA), density, viscosity and elemental analysis. Indiana limestone cores were used with average porosity of 16% and permeability ranges (9-13) md. X-ray diffraction (XRD) was used to analyze the mineral and clay content in the cores. Sludge tests were used to examine the acid and oil compatibility using anaging cell under 500 psi and 160°F with oil to an acid ratio of 1:1. Coreflooding experiments under reservoir condition were done with the selected two acid systems, 15 wt. % HCl and achelating agent. Indiana limestone cores with a permeability of 7-12 md were initially saturated with the crude oil then acid was injected until breakthrough. The injected acid volume was recorded and CT-scan imaging of the cores after the acid treatment was used to evaluate the structure and the propagation of the wormhole. The effluent fluids were analyzed by inductively coupled plasma (ICP) and pH measurements.
The results for a Kuwaiti crude oil showed the formation of 13 wt% sludge with 15 wt% HCl and it increased to 19 and 30 wt% with increasing acid concentrations to 20 and 28 wt%, respectively. The presence of iron(III) in the system increased the sludge precipitation to 17.8 wt% at 15 wt% HCl and 3,000 ppm iron concentration. The sludging decreased to 7.5 wt% by adding 300 ppm coconut oil to the system. The formation of asphaltene sludge in the carbonate acidizing retards the wormhole propagation. Hence, the injected acid volume to the breakthrough decreased from 1 to 0.4 by adding 300 ppm coconut oil to the acid system. A conical wormhole was formed with the injection of 15 wt% HCl, comparing to a uniform wormhole in the presence of coconut on the acid system. In the case of stimulating the cores with achelating agent (20 wt% GLDA), the coconut oil exceeds the expectations with the minimum pore volume needed to breakthrough compared to the GLDA alone or with the chemical dispersant B.
This study concluded that the use of dispersant can help reduce the asphaltene sludge and create better acid propagation through the core. The results can be employed to design the optimum acid formulation and create the desired wormhole in carbonate formations.
Hydraulic Fracturing has been used successfully in the oil and gas industry to enhance oil and gas production. Recent years have seen the great development of tight gas, coalbed methane, and shale gas. Different fluids were used as fracturing fluids in shale and sandstone formations, including the use of CO2, N2 and CO2 foam, slick water, crosslinked solutions, and oil-based fracturing fluids. The objective of this study is to develop an experimental setup to measure the breakdown pressure to initiate the fractures in shale and tight sandstone cores.
This study investigated the effect of injection flow rate, temperature, fluid viscosity, and fluid type on the breakdown pressure of different rock cores. 5 wt% KCl brine, slick water with a friction reducer, linear gel systems were used as a fracturing fluid. Kentucky, Scioto, Bandera, and Berea sandstone cores were used. Also, Mancos, Marcellus, and Barnett shale cores were used in this study. Finally, the behavior of the breakdown pressure was examined as a function of the back pressure (0, 100, 300 psi).
The preliminary results show that the breakdown pressure increased as the injection flow rate increased. Where the breakdown pressure increased from 438 to 1,000 psi as the flow rate increased from 5 to 10 cm3/min in case of 5 wt% KCl with Kentucky sandstone cores. The breakdown pressure increased in Marcellus shale to 1,800 psi in case of 5 wt% KCl at 5 cm3/min. As the fluid viscosity increased the breakdown pressure increased, it increased to 1,115 psi in case of 2 gptg friction reducer (5 cp) comparing to 5 wt% KCl (1.1 cp) case at 5 cm3/min. A straight line relationship was found between the breakdown pressure and the logarithmic scale of the fluid viscosity.
This study will give recommendations for the fluid viscosity, type, and the injection flow rate that will improve the efficiency of the hydraulic fracturing operation.
Progressive cavity pumps (PCP) have been used as artificial lift system for heavy oil lifting, low productivity wells and other challenging conditions which are common characteristics of brownfields. In addition to those conditions, there is the current complicated economic environment in which operating companies seek to reduce investments while enhancing field production operations with low-cost solutions aiming to increase the overall's field recovery factor.
The initial step when trying to enhance field production operations in wells operating with PCPs as artificial lift system is performing a well-level analysis. During this analysis, the existing operational conditions and its corresponding production are evaluated. The continuity and accuracy of this analysis is highly dependent on the data input for analysis purposes. For instance, the rate of production is required as input and due to the nature of operation in brownfields, this value is not measured with the required frequency needed for performing a proper production enhancement analysis.
This paper aims to provide a simple, automated, and accurate way to perform a calculated rate of production that is cost effective and easy to maintain, capable of being used during field production operations enhancement analysis, and applicable to wells operating with PCPs as artificial lift in heavy oil conditions, using regression and analytical methods.
Both methods are being used part of a digital oilfield solution implemented in a heavy oil brownfield with telemetry-instrumented PCP wells. This solution is working inside a production operations platform that validates input data, manages different frequencies and types of data, and automatically calculates a production rate, which is then pushed to a visualization dashboard.
Results provide an accurate production rate estimate suitable for reservoir engineering analyses while providing insight for the production operations enhancement.