Optimization and Field Test of a Chelating Acid System for Scaled Gas Wells in the Hechuan Gas Field

The Hechuan gas field is one of the tight gas reservoirs with the highest formation water salinity in China. The content of metal ions, such as calcium, magnesium, iron, and barium, is as high as 20 g/L. Severe scales in near-wellbore reservoir blocks the gas and liquid flow paths, affecting the normal production of gas wells. The analysis of scale samples shows that the scale compositions in the Hechuan gas field are complex, which are composed of calcium carbonate, calcium sulfate, barium sulfate, iron salt, silicate, and other inorganic scales. To dissolve these scales, 14 kinds of laboratory self-made chelating acids named AST-01 to AST-14, sequentially, were evaluated by the descaling rate, in which the chelating acid AST-01 was selected with a dissolution rate of 77.7%. Meanwhile, the optimal concentration and reaction time of AST-01 were investigated, and the concentrations of the corrosion inhibitor, the iron ion stabilizer, and surfactants were also optimized. Then, a chelating acid descaling formula was obtained, which was 15~20% of AST-01 chelating acid + 1.5~2.0% of corrosion inhibitor + 2.5% of iron ion stabilizer + 0.3% of drainage aid. A pilot field trial of this descaling formula was applied in a Hechuan X1 well. A remarkable result was obtained in that the shut-in tubing pressure recovery rate was increased by 14 times, the gas production was increased by 10 times, and the gas well resumed to produce continuously again.

Using the Modified Resistivity–Porosity Cross Plot Method to Identify Formation Fluid Types in Tight Sandstone with Variable Water Salinity

It is generally difficult to identify fluid types in low-porosity and low-permeability reservoirs, and the Chang 8 Member in the Ordos Basin is a typical example. In the Chang 8 Member of Yanchang Formation in the Zhenyuan area of Ordos Basin, affected by lithology and physical properties, the resistivity of the oil layer and water layer are close, which brings great difficulties to fluid type identification. In this paper, we first analyzed the geological and petrophysical characteristics of the study area, and found that high clay content is one of the reasons for the low-resistivity oil pay layer. Then, the formation water types and characteristics of formation water salinity were studied. The water type was mainly CaCl2, and formation water salinity had a great difference in the study area ranging from 7510 ppm to 72,590 ppm, which is the main cause of the low-resistivity oil pay layer. According to the reservoir fluid logging response characteristics, the water saturation boundary of the oil layer, oil–water layer and water layer were determined to be 30%, 65% and 80%, respectively. We modified the traditional resistivity–porosity cross plot method based on Archie’s equations, and established three basic plates with variable formation water salinity, respectively. The above method was used to identify the fluid types of the reservoirs, and the application results indicate that the modified method agrees well with the perforation test data, which can effectively improve the accuracy of fluid identification. The accuracy of the plate is 88.1%. The findings of this study can help for a better understanding of fluid identification and formation evaluation.

Reservoir characteristics and control mechanism of resistivity low-contrast oil pays in Chang 8 tight sandstone of Longdong West area, Ordos Basin

Log interpretation and evaluation of tight sandstone reservoir in Chang 8 Member of Longdong West area, Ordos Basin, China, are facing great challenges due to the co-development of normal oil pay and resistivity low-contrast oil pay. To better guide the exploration and development of oil resources in this area, the reservoir characteristics and control mechanism of resistivity low-contrast oil pay were studied. Firstly, the reservoirs were divided into resistivity low-contrast oil pay (RLP) and normal oil pay (NP) based on the relative value of the apparent resistivity increase rate. Then, the difference of reservoir characteristics between RLP and NP is analyzed by comparing a series of experimental data and real logging data in those two reservoir types. Finally, the control mechanism of RLP was studied from reservoir micro-factors and regional macro-factors, respectively. It is found that the chlorite and illite are the most abundant clay minerals in RLP and NP, respectively. Compared with NP reservoir, the average porosity of RLP is better, but the pore space is mainly composed of micropores, which lead to smaller average pore throat radius and poor pore structure. The high irreducible water saturation and high formation water salinity reduced the reservoir resistivity from micro-aspect. Besides, the difference of hydrocarbon expulsion capacity of source rock and the regional difference of formation water salinity controlled the distribution of RLP and NP. Comprehensive consideration of the reservoir micro-factors and regional macro-factors is important to carry out effective logging interpretation and evaluation.

REVISING THE INTERPRETATION OF COMPLEX CARBONATE RESERVOIRS WITH THE USE OF NOVEL ADVANCED LOGS INTEGRATION TECHNIQUES

The Alta field in the Barents Sea was discovered in 2014. The reservoir formation is primarily carbonate rocks with high formation water salinity. Extensive waterflooding processes have led to an approximately 200-m rise of water level. The complexities anduncertainties regarding imbibition, current free waterlevel, and pseudo fluid contacts within the field translateinto uncertainty in the hydrocarbon volume estimation. Initial, triple-combo-based petrophysical evaluations have already been updated using advanced log measurements, as reported in an earlier publication. The evaluation is now consolidated by using two new techniques relying on advanced spectroscopy logging and combination with dielectric dispersion logging. Their objective is to further reduce the uncertainty in water saturation associated with variable apparent water salinity. The present contribution proposes a workflow that relies on two novel techniques. The first technique is a direct quantitative measurement of formation chlorine concentration from nuclear spectroscopy, which helps resolve the formation's apparent water salinity and provides a way to calibrate formation matrix sigma. The second technique relies on the existing combined inversion of dielectric dispersion and formation sigma, including explicitly invasion effects. This second technique benefits from the first technique's insight to adjust sigma interpretation and provide bounds for possible salinity variations. The workflow provides robust flushed and unflushed zone salinities, here the most uncertain and variable parameter, combined with accurate estimations of virgin and residual hydrocarbon saturations. The quantification of dielectric textural parameters describing how the water is shaped inside the formation is also improved, contributing to the improvement of virgin zone hydrocarbon saturation estimation.

Analysis of main controlling factors and identification method of Jurassic low resistivity reservoir in Huanxian area, Ordos Basin

<p>The Ordos Basin is located in the central and western part of China, which is rich in oil resources in Mesozoic strata. Huanxian area is located in the west of the Ordos Basin, covering an area of about 3000 km<sup>2</sup>. With the wide distribution of Jurassic low resistivity reservoir, it is difficult to identify reservoir fluid by logging, which restricts the efficient promotion of oil resources exploration and development in this area to a certain extent.</p><p>Based on the basic geological law, this study makes full use of the data of oil test conclusion, production performance and formation water analysis to deeply analyze the genesis of low resistivity reservoir in this area. The average formation water salinity of Jurassic in Huanxian area is 63.5g/l. Through the correlation analysis of mathematical methods such as fitting and regression, the formation water salinity and reservoir apparent resistivity show a good negative correlation in the semi logarithmic coordinate, and the correlation coefficient is 0.78. Therefore, it is considered that the main controlling factor for the widespread development of low resistivity reservoir in this area is the high formation water salinity. Irreducible water saturation, clay mineral content and nose bulge structure amplitude are the secondary controlling factors for the development of low resistivity reservoir in this area, and their correlation coefficients with apparent resistivity are 0.23, 0.25 and 0.31, respectively.</p><p>On the basis of clarifying the genesis of Jurassic low resistivity reservoir in Huanxian area, the comprehensive identification of reservoir fluid type by logging is carried out. For the whole area, there are obvious differences in geological characteristics, so conventional methods such as cross plot method of acoustic time difference and apparent resistivity can not effectively identify reservoir fluid. According to the main controlling factors of reservoir apparent resistivity, the salinity of formation water is combined with apparent resistivity and resistivity index of reservoir respectively to establish the cross plot. Using these two kinds of cross plot, the accuracy of reservoir fluid type identification is 62.9% and 88.6% respectively. This method can meet the accuracy requirements of reservoir fluid identification, realize the rapid identification of reservoir fluid types in the whole area, and provide technical support for efficient exploration and development of Jurassic low resistivity reservoir in this area.</p>

Thermal Stability and Compatibility of Surfactants in Presence of Formation Water Salinity under Reservoir Conditions

In the surfactant alternating gas injection, the injected surfactant slug is remained several days under reservoir temperature and salinity conditions. As reservoir temperature is always greater than surface temperature. Therefore, thermal stability of selected surfactants use in the oil industry is almost important for achieving their long-term efficiency. The study deals with the screening of individual and blended surfactants for the applications of enhanced oil recovery that control the gas mobility during the surfactant alternating gas injection. The objective is to check the surfactant compatibility in the presence of formation water under reservoir temperature of 90oC and 120oC. The effects of temperature and salinity on used surfactant solutions were investigated. Anionic surfactant Alpha Olefin Sulfonate (AOSC14-16) and Internal Olefin Sulfonate (IOSC15-18) were selected as primary surfactants. Thermal stability test of AOSC14-16 with different formation water salinity was tested at 90oC and 120oC. Experimental result shows that, no precipitation was observed by surfactant AOSC14-16 when tested with different salinity at 90oC and 120oC. Addition of amphoteric surfactant Lauramidopropylamide Oxide (LMDO) with AOSC14-16 improves the stability in the high percentage of salinity at same temperature, whereas, the surfactant blend of IOSC15-18 and Alcohol Aloxy Sulphate (AAS) was resulted unstable. The solubility and chemical stability at high temperature and high salinity condition is improved by the blend of AOSC14-16+LMDO surfactant solution. This blend of surfactant solution will help for generating stable foam for gas mobility control in the methods of chemical Enhanced Oil Recovery (EOR).

Experimental evaluation and tomographic characterization of polymer gel conformance treatment

Excessive water production from hydrocarbon reservoirs is considered as one of major problems, which has numerous economic and environmental consequences. Polymer-gel remediation has been widely used to reduce excessive water production during oil and gas recovery by plugging high permeability zones and improving conformance control. In this paper, we investigate the performance of a HPAM/PEI (water-soluble Hydrolyzed PolyAcrylaMide/PolyEthyleneImine) polymer-gel system for pore space blockage and permeability reduction for conformance control purpose. First, the gel optimum composition, resistance to salt and long life time are determined using bottle tests as a standard method to specify polymer-gel properties. Then the performance and stability of the optimized polymer-gel are tested experimentally using coreflood tests in sandpack core samples. The effects of different parameters such as gel concentration, initial permeability of the cores, and formation water salinity on the final permeability of the cores are examined. Finally, the gel flow-induced local porosity changes are studied in both a sandpack core and a real carbonate sample using grayscale intensity data provided from 3D Computed Tomography (CT) images in pre- and post-treatment states. The results show that the gel system has a good strength at the middle formation water salinity (in the range of typical sea water salinity). In addition, despite a higher performance in high permeability cores, the gel resistance to degradation in such porous media is reduced. The CT images reveal that the initial porosity distribution has a great influence on the performance of the gel to block the pore space.