During water-alternating-gas (WAG) flooding for heavy oil reservoirs, the adverse mobility ratio leads to a considerable amount of injection gas fingering through and overriding the oil zone. To improve the recovery efficiency of the WAG process in a Saskatchewan (Canada) heavy oil reservoir, the Saskatchewan Research Council (SRC) conducted a laboratory feasibility study of augmenting the injection water with chemicals (alkaline/surfactant/polymer). The resulting process is known as CAG, or chemicalalternating-gas (CO2 or flue gas). SRC's integrated approach included interfacial tension (IFT) and rheology measurements, phase
behaviour studies, micromodel displacements, and corefloods to evaluate the effectiveness of the CAG process. The results showed that addition of ASP into the injection water could significantly lower IFT (to 10-2 mN/m) and improve mobility. The phase behaviour studies indicated that CO2 could be dissolved readily into reservoir heavy oil at moderate pressures (3.4-6.4 MPa), resulting in dramatic oil expansion (1.2-8.1%) and viscosity reduction (45-88%). It was also demonstrated that the presence of 70% N2 in the CO2 stream (i.e., flue gas) greatly reduced the gas solubility, causing negligible oil swelling and viscosity
reduction at the reservoir pressure. It was observed from micromodel displacement tests that CO2 viscous fingering and breakthrough occurred quickly even at a low pressure of 2.3 MPa, indicating the need to lower the capillary pressure between the heavy oil and porous media and add a mobility buffer between the CO2 and heavy oil. The coreflood results showed that a conventional CO2-WAG process recovered more incremental oil than a flue gas-WAG (9.43 vs. 3.58% OOIP), whereas a CO2- CAG and a flue gas-CAG recovered incremental oil of 27.43 and 22.07% OOIP, respectively. The comprehensive studies suggest that the CO2-CAG process holds promise for recovering Saskatchewan's tremendous heavy oil resources.
Gang, Cao (Daqing Oilfield Co. Ltd.) | He, Liu (Daqing Oilfield Co. Ltd.) | Guochen, Shi (Daqing Oilfield Co. Ltd.) | Mingyan, Lu (Daqing Oilfield Co. Ltd.) | Mingzhen, Liu (Daqing Oilfield Co. Ltd.) | Wang, Honghai (Daqing Oilfield Co. Ltd.) | Yunlong, Zhao (Daqing Oilfield Co. Ltd.) | Bo, Yu (Daqing Oilfield Co. Ltd.)
Daqing Oilfield is the largest continental oilfield in China. After 50 years development, the total quantity of drilling and artificial equipments of the oilfield has reached to a considerably large size and it is still increasing with a higher rate. Daqing Oilfield had to spend a lot in maintenance and renewal of the equipments. For example, only the replacement of artificial lifting equipments would cost 156.75 million USD each year. In the past tens years, Daqing Oilfield invested huge funding to improve the equipment management and recycling manufacturing techniques. After years of study, a set of management methodology was created and a series of rebuilding techniques were developed. This paper presented the practices both in drilling and production equipment management and rebuilding techniques. This paper also decribe the outlook of oilfield equipment management and rebuilding techniques in the future.
Guo, Shusheng (CNOOC China Limited Zhanjiang) | CAI, Jun (CNOOC China Limited Zhanjiang) | Khong, Chee Kin (Schlumberger) | Zuo, Julian Youxiang (Schlumberger) | o'keefe, Michael (Schlumberger) | Hausot, Andreas (Schlumberger K. K.) | Mullins, Oliver (Schlumberger)
Formation fluid samples can be obtained as surface samples or downhole samples. However, surface sample sampling requires the well to be completed and with production to surface of reservoir fluids from a one or more zone or sometimes multiple zones produced to surface. Downhole sampling can be performed without completing the well by using a formation tester in open hole or performed after completion. In addition, surface samples acquired by flowing the well tend to integrate the fluid over large vertical intervals in the well thereby precluding measurement of fluid gradients. In contrast, wireline sample acquisition and analysis enables vertical and, with multiple wells, lateral gradients to be resolved thereby greatly improving the understanding of the reservoir fluids. Sampled reservoir fluid produced from a zone or multiple zones is not as descriptive compared to point sample using a formation tester. Finally, fluid samples can be sent to the laboratory for analysis but this usually takes a long time; wireline sample acquisition with downhole fluid analysis plays a key role in elucidation of the complexities of reservoir fluids and often time the collected sample is just analyzed using available equipment at the wellsite.
Downhole fluid analysis (DFA) can be performed during sample acquisition with wireline formation testing tools. Sampling operation DFA can identify fluid type, contamination and possible phase changes thereby validating acquisition of a clean, single phase sample of the reservoir fluid if sampling is performed above bubble point pressure. Beyond simply obtaining a valid sample, DFA is used to determine many fluid parameters including compositional measurements such as weight mass fraction of percentages of CO2, C1, C2, C3-C5 or (C2-C5) and C6+ and relative asphaltene content enabling determination of gas oil ratio (GOR) or condensate gas ratio (CGR) derivation. Other currently available DFA measurements are insitu density and viscosity and calibrated fluorescence. Moreover, in special cases, the mass fraction of (diatomic) nitrogen can be determined using the 'missing mass' approach.
In this paper, laboratory validated EOS-based downhole fluid characterization that delump C3-C5 (or C2-C5) and C6+ into fulllength compositional data was applied to the DFA examples in case studies to maximize the value of DFA data. Particular focus is placed on analysis of CO2 and N2 non-hydrocarbon gases. The gas samples acquired in the examples discussed here were not analyzed at laboratory and only assayed by DFA and by available well site equipment only to C4, giving CO2, N2 and hydrocarbon gas fractions. Reservoir fluid characterization is optimized for this DFA measurement by comparison with an Equation of State (EOS) analysis. Specifically, improved by using an algorithm for delumping, the DFA measurements were validated using laboratory validated Equation of State (EOS)-based analysis downhole fluid characterization algorithm. The delumped DFA measurements were used for flow assurance, hydrocarbon source and compartmentalization analysis. The gas samples' phase envelopes derived from the delumped DFA measurements are used for reservoir characterization, reservoir continuity analysis and management decisions.
Based on the analysis of fracture classification??controlling factors and distribution characteristic, in this article we established the fracture intelligent recognition system. In the reservoir fracture forecast modeling aspect, we established one one FM2 (fracture modeling based on fracture mechanics) system by combining geological statistics and fracture mechanics. Based on the modern fracture mechanics, has established FM2 system. The model has not only considered the temperature field and strain field coupling effect, and introduces Green Strain tensor in the small distortion analysis. Because of the reservoir existence varying degree's aeolotropies, so in the elastoplasticity stress and strain field simulation, mainly uses kinematics hardening theory. But the fracture distribution also influenced by later period structure change and others kinds of factors. In order to compensate the influence of these factors to facture distribution, the auto-adapted intelligent field control fracture modeling method is first raised in this article. Based on the common field control fracture modeling method, by contrasting the fracture distribution data obtained from micro electrical receptivity well log, modify the boundary condition and modulus by according to the error to make the simulation results achieve the most superior match.
Key words: fracture modeling; fracture mechanics; FM2; intelligent simulation;
In the reservoir, the fracture is one kind of widespread distributed important geologic structure. In the low seepage reservoir, fracture has provided the infiltration channel and governing the oil distribution. The fracture existence strengthened the reservoir anisotropism. And in the water injection development, it's easy to cause the irrigation to flee along the fracture, and affect the effect of water injection development. As deepening studying of the formation mechanism of fracture, the understanding of fracture has being constantly revised and encriced. G. H. Murry  taked the cross section as a curved beam, and derived a formula between the geometric curvature of the cross section and fracture porosity. Then the stochastic modelling of fracture networks originated in percolation studies [2-4] and its wider application to rock engineering was promoted in the 1980s by the work of several research groups. The general approach is to treat locations, persistence (size), orientation and other properties of the fractures as random variables with inferred probability distributions. To reduce the complexity of the problem, simple geometry is assumed for fractures with the most common geometries being straight lines for 2D fractures and ellipses for 3D fractures, although infinite 2D planes (termed Poisson planes) are also used. In the simplest case of no spatial correlation, once the parameters of the distributions are inferred, the rock fracture model can be constructed by Monte Carlo simulation. //But discrete fracture network did not consider the fracture mechanics, for the present fracture mechanics, five different failure criteria can be assumed, namely Columb-Mohr criterion, Tresca criterian, Zienkiewice-Pande criterian, Mises criterian, Drucker-Prager criterion. Fracture mechanics has given few great fracture simulation results in micro-fracture simulation. V. Cannillo used a numerical fracture propagation model based on finite element simulations of realistic composite microstructures for the glass matrix material, by using finite elements coupled with selected failure criteria (Griffith and Weibull approaches) implemented inside the elements. Zhenjun Yang used crack growth criterion which derived based on the Griffith energy concept and the cohesive zone model for modelling fracture in elastic-plastic ductile materials. By using of the modern fracture mechanics and auto-adapted intelligent field control fracture modeling method, this paper has established FM2 system. Based on this system, we has completed Hei47 area??Hei59 area??Hei79 area??Hei89 area fracture simulation of Jilin Oilfield . In these four areas, the high value of Mises stress and fracture density most distributes nearby the fault and large displacement region.
The growing interest in deepwater exploration drilling in the Asia Pacific region has resulted in the first exploration wells being drilled in the deepwater area's of South East Asia. As these deepwater exploration wells were being drilled, the first well control issues associated with kicks and losses in the carbonate formations have also been encountered. Over 200 wells have been drilled to date in South East Asia using managed pressure drilling techniques. MPD technologies are now routinely used on floating rigs to solve the loss kick scenario's encountered in the fractured carbonates, the use of MPD equipment in deepwater (+400m) operations provides a number of additional technical challenges that are now also being addressed.
This paper provides an overview of the current MPD applications and techniques used from floating rigs. The paper then highlights the unique challenges that are associated with the implementation of managed pressure drilling in a deepwater environment. In the near future as reserves are discovered and developed in the deepwater carbonate reservoirs, solutions to the drilling challenges will have to be found to allow commercial development of these deepwater reserves in the Asia Pacific Region.
Liu, Bingshan (Research Institute of Petroleum Exploration and Development) | Zhou, Shi (CNPC Chuanqing Drilling Engineering Company Limited) | Zhang, Shunyuan (Research Institute of International Technologies of CNPC Drilling Research Institute)
The two main target formations of shallow horizontal wells in Sudan are Bentiu formation and Aradeiba formation. They are becoming more and more important with the exploration of oilfield, and they are all about or shallower than 1000m underground. The stratums are loose, so some measures are adopted to ensure the success of drilling operations: studying the stability of the borehole, optimizing the hole structure and casing program, establishing the drilling fluid system and its formulation.
We get the pore pressure, collapse pressure, and the fracture pressure by studying the formation pressure system using professional software upon the logging data. Study the relationship between the content of clay and the stability of borehole. It shows that the clay content has significant effect to borehole stability in Sudan. Then we analyze the collapse period of the upper stratums. The time window is about from 5 days to 7days. Based on the results and the study of the data of those wells drilled, the horizons of leakage and collapse are indicated. According this and the formation pressure, we optimize the hole structure and casing program. Finally, the KCl-polymer system is sifted as the drilling fluid. We determine the mud density according to the formation pressure first. Then the contents of KCl and the additives are indicated by experiments. According the experiments, the ideal percentage of KCl is form 6% to 8%, and the percentage of QS-2 in the drilling fluid using in field is from 3% to 4%. Now there are 5 shallow horizontal wells have been drilled in Sudan. The research achievements have been applied in the drilling operations. The average drilling cycle is about 17 days. Moreover, the hole diameter enlargement rate is decreased remarkably.
The formation damageability of drilling and completion fluids on horizontal wells is more critical than on vertical wells, due to longer horizontal section of horizontal wells and the larger reservoir exposure area during operations, resulting in rapid productivity decrease. As such, acidizing techniques for horizontal well is an important solution to increase the reservoir productivity. However, the long horizontal section passes through various lithology layers due to geological heterogeneity. This cause the mud invasion time and formation damage degrees are different in various layers. All factors will bring in potential negative impacts derived from common acidizing and coiled tubing acidizing and lead to non-uniform acid distribution and poor acidizing effect. Therefore, it is necessary to make use the mechanical multi-section acidizing technology. For that, the wellbore should be divided into several sections according to the reservoir lithology, physical characteristics, and damage degree to realize the purposes of acid uniform distribution and productivity increase. Conventional process is hard to acidize the multi-sections in horizontal wells, because the deflected section exist in horizontal well and the target layer is located at horizontal section, which make downhole string operations more complicated, and stresses in horizontal well is quite different from that of vertical well. The ball-shooting sliding sleeve mechanical multi-section acidizing string is available to resolve these problems successfully. This string is made up with safety joint, connected vessel, hydraulic anchor, centralizer, spring sand blasting devise, K344-110 packer, low density ball, etc, with 40 MPa tolerance pressure and 90? tolerance temperature. It can perform enforced sectionalizing. Four times shooting, five sections treatments, and residual liquid's reverse circulation cleanup and backflow after acidizing process can be carried out through the original production string in this technique. In addition, only 110 mm diameter of the packer outer, additional installation of centralizer at two ends and the application of connected vessel can reduce not only upward loads of the string, but also potential hazards of pipe stuck, and provide the feasibility for releasing pipes and fishing operations. Up to now, 12 wells and 36 layers have been conducted the multi-section acidizing technique in Daqing Oilfield, the greatest treatment is up to 4 sections with one trip string, the success rate is 100%. Considerable yield increase effect is available. it is statistic 5.9 m3/d average fluid increase, 4.8 t/d average oil increase, and 182% the average productivity increase rate of single well in the early stage after the operation. The horizontal well acidizing technique provides an efficient way to develop oil field in the peripheral areas of Daqing Oilfield and has a wide application in prospect with lower costs, higher efficiency and simpler operation.
Wang, Jiahuai (Xinjiang Petr. Admin. Bureau) | Xie, Bin (Oil Production Technology Research Institute of Xinjiang Oilfield Company) | Luo, Xiang-jie (Oil Production Technology Research Institute of Xinjiang Oilfield Company) | Zheng, Hong (Oil Production Technology Research Institute of Xinjiang Oilfield Company) | Ma, Xin-Ming (Oil Production Technology Research Institute of Xinjiang Oilfield Company)
The punched or slotted screen pipe is used for the well completion of the shallow heavy oil horizontal well in Xinjiang oilfield. But the sand is still produced significantly in some wells Because the permeability is high, the formation pressure is low, the oil sands cementation at normal temperature is strong, it is hard for the conventional hydraulic sand washing to shatter the oil/sand bed, the sand washing fluid is lost substantially, the sand carrier fluid cannot reverse out which cannot effectively remove the sand deposition in the horizontal section. Therefore, the Jet Negative Pressure Sand Removal Technique by Concentric Tubing and assorted tools were designed and developed. The computational software of sand-washing optimization was developed. The application results in 14 wells proves that this Technique can efficiently and completely remove the sand deposition in the wellbore of heavy oil horizontal well which solves the production reduction and off production problem caused by sand deposition along the wellbore in the heavy oil horizontal wells.
The concentrations of heavy metals in the soil at oil and gas production areas were appraised at Ebocha and Akri communities in Niger Delta region of Nigeria. The pollution/contamination loading indexes of Zinc (Zn), Nickel (Ni), Copper (Cu), and Lead (Pb) in the two communities were determined from soil samples collected in eight locations (in triplicate) in each community using Atomic Absorption Spectrophotometer (AAS).
It was observed that Ebocha was slightly polluted with lead (contamination/pollution index, c/p = 1.3), severely contaminated with zinc (c/p = 0.642) and slightly contaminated with copper(c/p = 0.123). Omoku was also slightly contaminated with zinc (c/p = 0.225) while all other sampling locations at Ebocha were very slightly contaminated with zinc, copper nickel and lead (c/p <0.1). Akri was very slightly contaminated in all the sampling locations except for Afia-afor where lead slightly contaminated the soil (c/p = 0.113).
A significant correlation (p <0.01) was obtained for zinc (r = 0.65) while there was no significant correlation (0.05 <p <0.01) obtained for Ni (r = -0.14), Cu (r = 0.22), Pb (r = -0.08), Mn (r = 0.38) and Fe (r = 0.54). This correlation showed that the sources of the heavy metals in both communities are different. It was also observed that the increased concentration of heavy metals in oil and gas production areas is more due to other associated human activities in the areas than oil and gas core production activities.
Polyacrylamide microgel nanospheres were synthesized by inverse microemulsion polymerization with redox initiators on the basis of the preparation of water-in-oil (W/O) microemulsion with diesel oil, sorbitan monooleate, polyethylene glycol sorbitan monostearate, acrylamide, N,N'-methylenebisacrylamide and deionized water. By adopting a twice synthesis process, polymer content can be substantially lifted from 24.43 wt% to 35.04 wt%. Moreover, it's proved that nanospheres can expand from the initial 50nm or so to several microns after water absorption.
In this paper, synergy effects of the emulsifiers (sorbitan monooleate and polyethylene glycol sorbitan monostearate) separately with alkalis and surfactants are firstly proposed and verified via the achievement of ultra-low interfacial tension (IFT). Profile control and oil displacement tests by sandpacks further demonstrated the promising future of nanospheres in enhanced oil recovery (EOR) with incremental oil recovery over 20% OOIP after primary recovery.