Reserve Recovery Research Articles

Updating a reservoir geological model in order to optimize waterflooding when extracting residual oil reserves from stagnant zones

Background. In the Russian Federation, as well as in many other oil and gas producing countries, waterflooding technology is frequently used as a secondary method of oil production. This technology is aimed, on the one hand, at reservoir pressure maintenance (RPM), and, on the other, at enhancing oil recovery and intensifying oil production. The negative consequences of non-stationary waterflooding can be the premature watering of the produced wells and the imbalance of the reservoir pressure maintenance system, as well as the formation of stagnant and weakly drained zones of the reservoir with residual reserves of hard-to-recover oil.Aim. To improve the efficiency of non-stationary waterflooding under the conditions of high geological and anthropogenic heterogeneity of oil and gas reservoirs in a floating oil reservoir propped up by edge and bottom waters.Materials and methods. We used geological and field information collected on the site of the AB1-2 development object of the Kechimovskoye field in the Western Siberian region. A new methodological approach to optimizing the process of non-stationary waterflooding under complicated conditions of geological and anthropogenic heterogeneity is proposed, including the construction of an improved geological model and the solution of a number of experimental problems using the Hurst method, the Pareto distribution principle and the theory of catastrophes.Results. Using a new version of the geological model of the area of the AB1-2 development object of the Kechimovskoye field and the available geological and field information, we clarified the position of the oil-water contact (OWC) and the correlation of the well section, taking into account the working intervals of production and injection wells. Geological and technical measures were formulated to improve the efficiency of the object under development.Conclusions. An effective development of the geologically complex AB1-2object of the Kechimovskoye field is impossible without updating its geological model. Such updating should be aimed at determining the location of residual reserves in the area and section of the reservoirs, identifying the regularities of the mechanism of oil reserve recovery, assessing the efficiency of the reservoir pressure maintenance system, and developing complex geological-technological measures for achieving the approved value of the final oil recovery factor. The expected efficiency of the proposed optimization methodology provides for additional oil production, a reduction in the flow rate of injected and withdrawal of produced water.

Self-diffusion flow and heat coupling model applicable to the production simulation and prediction of deep shale gas wells

Clarifying the flow laws of shale gas under high temperature and high pressure is the prerequisite to accurately predicting the productivity of deep shale gas wells. In this paper, a self-diffusion flow model of flow field and temperature field coupling (referred to as self-diffusion flow and heat coupling model) was established based on the previously proposed self-diffusion flow model, while considering the influence of the temperature field change. Then, its calculation result was compared with that of the flow model based on Darcy's law and Knudsen diffusion (referred to as modified Darcy flow model). Based on the self-diffusion flow and heat coupling model, the self-diffusion flow behaviors of deep shale gas under the influence of temperature field change were analyzed, and the influence of bottomhole temperature on the degree of reserve recovery of deep shale gas was discussed. Finally, the self-diffusion flow and heat coupling model was applied to simulate the production of one shale-gas horizontal well in the Upper Ordovician Wufeng Formation–Lower Silurian Longmaxi Formation in the Changning Block of the Sichuan Basin. And the following research results were obtained. First, at the same parameters, the shale gas production calculated by the self-diffusion flow and heat coupling model is higher than the result calculated by the modified Darcy flow model. Second, when temperature field change is taken into consideration, the self–dviffusion coefficient profile presents a peak, the gas density profile presents a valley and the data points corresponding to the peak/valley move synchronously to the internal formation, which indicates that the self–diffusion coefficient influences the gas mass transfer rate, and the influence range of near well low temperature on gas self-diffusion increases continuously as the production continues. Third, when the bottomhole temperature is lower than the formation temperature, the self–diffusion coefficient of the gas near the well decreases and the gas is blocked near the well, which reduces the gas well production. Fourth, the production simulation result of the case well shows that the self-diffusion flow and heat coupling model can predict the production of deep shale gas more accurately if temperature field change is taken into consideration. In conclusion, the self-diffusion flow and heat coupling model established in this paper is of higher reliability and accuracy and can be used for productivity simulation and prediction of deep shale gas wells. The conclusion of this paper has certain guiding significance for deep shale gas production and gas well productivity prediction.

The Dynamics of the Anaerobic Energy Contribution During a Simulated Mass-Start Competition While Roller-Ski Skating on a Treadmill.

The purposes of this study were: 1) to investigate the anaerobic energy contribution during a simulated cross-country (XC) skiing mass-start competition while roller-ski skating on a treadmill; 2) to investigate the relationship between the recovery of the anaerobic energy reserves and performance; and 3) to compare the gross efficiency (GE) method and maximal accumulated oxygen deficit (MAOD) to determine the anaerobic contribution. Twelve male XC skiers performed two testing days while roller skiing on a treadmill. To collect submaximal data necessary for the GE and MAOD method, participants performed a resting metabolism measurement, followed by low-intensity warm up, 12 submaximal 4-min bouts, performed using three different skating sub-techniques (G2 on a 12% incline, G3 on 5% and G4 on 2%) on three submaximal intensities on day 1. On day 2, participants performed a 21-min simulated mass-start competition on varying terrain to determine the anaerobic energy contribution. The speed was fixed, but when participants were unable to keep up, a 30-s rest bout was included. Performance was established by the time to exhaustion (TTE) during a sprint at the end of the 21-min protocol. Skiers were ranked based on the number of rest bouts needed to finish the protocol and TTE. The highest GE of day 1 for each of the different inclines/sub-techniques was used to calculate the aerobic and anaerobic contribution during the simulated mass start using the GE method and two different MAOD approaches. About 85–90% of the required energy during the simulated mass-start competition (excluding downhill segments) came from the aerobic energy system and ~10–15% from the anaerobic energy systems. Moderate to large Spearman correlation coefficients were found between recovery of anaerobic energy reserves and performance rank (rs = 0.58–0.71, p < 0.025). No significant difference in anaerobic work was found between methods/approaches (F(1.2,8.5) = 3.2, p = 0.10), while clear individual differences existed. In conclusion, about 10–15% of the required energy during the periods of active propulsion of a 21-min simulated mass-start competition came from the anaerobic energy systems. Due to the intermittent nature of XC skiing, the recovery of anaerobic energy reserves seems highly important for performance. To assess the anaerobic contribution methods should not be used interchangeably.

Mechanism of Enhanced Oil Recovery for In-Depth Profile Control and Cyclic Waterflooding in Fractured Low-Permeability Reservoirs

When fractured low-permeability reservoirs enter a high water cut period, injected water always flows along fractures, water cut speeds increase rapidly, and oil production decreases quickly in oil wells. It is difficult to further improve the oil recovery of such fractured low-permeability reservoirs. In this paper, based on the advantages of in-depth profile control and cyclic water injection, the feasibility of combining deep profile control with cyclic water injection to improve oil recovery in fractured low-permeability reservoirs during the high water cut stage was studied, and the mechanisms of in-depth profile control and cyclic waterflooding were investigated. According to the characteristics of reservoirs in Zone X, as well as the fracture features and evolution mechanisms of the well network, an outcrop plate fractured core model that considers fracture direction was developed, and core displacement experiments were carried out by using the HPAM/Cr3+ gel in-depth profile control system. The enhanced oil recovery of waterflooding, cyclic water injection, and in-depth profile control, as well as a combination of in-depth profile control and cyclic water injection, was investigated. Moreover, variations in the water cut degree, reserve recovery percentage, injection pressure, fracture and matrix pressure, and water saturation were monitored. On this basis, the mechanism of enhanced oil recovery based on the combined utilization of in-depth profile control and cyclic waterflooding methods was analyzed. The results show that in-depth profile control and cyclic water injection can be synchronized to further increase oil recovery. The recovery ratio under the combination of in-depth profile control and cyclic water injection was 1.9% higher than that under the in-depth profile control and 5.6% higher than that under cyclic water injection. The combination of in-depth profile control and cyclic water injection can increase the reservoir pressure; therefore, the fluctuation of pressure between the matrix and its fractures increases, more crude oil flows into the fracture, and the oil production increases.

Fracturing Fluids and Their Application in the Republic of Croatia

Hydraulic fracturing operations are performed to enhance well performance and to achieve economic success from improved production rates and the ultimate reserve recovery. To achieve these goals, fracturing fluid is pumped into the well at rates and pressures that result in the creation of a hydraulic fracture. Fracturing fluid selection presents the main requirement for the successful performance of hydraulic fracturing. The selected fracturing fluid should create a fracture with sufficient width and length for proppant placement and should carry the proppant from the surface to the created fracture. To accomplish all those demands, additives are added in fluids to adjust their properties. This paper describes the classification of fracturing fluids, additives for the adjustment of fluid properties and the requirements for fluid selection. Furthermore, laboratory tests of fracturing fluid, fracture stimulation design steps are presented in the paper, as well as a few examples of fracturing fluids used in Croatia with case studies and finally, hydraulic fracturing performance and post-frac well production results. The total gas production was increased by 43% and condensate production by 106% in selected wells including wellhead pressure, which allowed for a longer production well life.

Research on Von Bertalanffy model and its application for predicting recoverable reserves and production of oilfield

Water drive type curves are simple, convenient and practical in reservoir engineering, which is widely used in reservoir production performance analysis. However, the commonly used water drive type curve can only draw one curve between water cut and recoverable reserves recovery degree, which greatly limits the application range of water drive curve. At the same time, the fitting of straight line section of water drive type curve is often affected by artificial selection, and the error is large. In order to better describe and reflect the rising law of water cut in different type reservoirs, the new water drive type curve is established, and the relationships between water cut and cumulative production, water cut and recovery degree of recoverable reserves are derived. Through MATLAB software programming and multi parameter fitting method, the parameters in the new water drive type curve can be easily calculated. The f w-R * curve shape of the new model includes convex curve, concave curve and S-shape curve. The new water drive type curve is applied to two actual reservoirs. The new curve fits well with the low water cut stage of the Baolang oilfield, and the error is small, which can be used to predict the future production performance of the oilfield. At the same time, the new water drive type curve is consistent with the change trend of the whole production stage of the Saertu oilfield, and the error is small, too. which can be used for the prediction of the whole production period and high water cut stage of the reservoir. The new model expands the application range of water drive type curve and provides reference for production performance prediction of other similar oilfields.

Change laws of water invasion performance in fractured–porous water-bearing gas reservoirs and key parameter calculation methods

In order to develop fractured–porous water-bearing gas reservoirs efficiently, it is necessary to understand the change laws of water invasion performance. Based on the π theorem, this paper adopted the dimensionless parameter that can reflect the change characteristics of water invasion performance to design the physical simulation experimental scheme of water invasion performance. The full-diameter cores taken from the reservoir of one certain fractured–porous water-bearing gas reservoir in the central Sichuan Basin were selected to carry out physical simulation experiment of water invasion performance. Then, by virtue of numerical inversion, the experimental results were converted into evaluation parameters of water invasion performance in water-bearing gas reservoirs. Afterwards, the change laws of water invasion performance in fractured–porous water bearing gas reservoirs were investigated, and the method for calculating key water invasion performance evaluation parameters and water volume was established. Finally, water invasion performance analysis and aquifer size evaluation were conducted with the Xu 2 Member gas reservoir, Upper Triassic in the Zhongba gas field of the Sichuan Basin as an example. And the following research results are obtained. First, in fractured–porous gas reservoirs with edge and bottom water, water invasion and gas production occur simultaneously. Before water production, there is a linear relationship between bottom hole pressure and reserve degree of reserve recovery. After water production, water invasion speeds up and the water–gas ratio (WGR) rises rapidly and finally approaches to a stable WGR of higher level. Second, the bottom hole pressure drop rate before water production and the stable WGR are mainly affected by the water volume, and the degree of reserve recovery per unit pressure drop and the stable WGR can be used to evaluate the water volume. Third, a method for mutual interpretation and evaluation of the aquifer size and the reserve degree of reserve recovery per unit pressure drop before water production and the stable WGR of fractured–porous gas reservoirs with edge and bottom water is established. In conclusion, the water invasion performance curve of the gas reservoir agrees with the core simulation experimental results. Based on the known water volume of a gas reservoir, the stable reserve degree of reserve recovery per unit pressure drop before water production and the stable WGR can be predicted; and on the basis of the stable WGR, the water volume of a gas reservoir can be predicted. The prediction results are in line with the production performance, providing a theoretical support for water invasion performance prediction and overall water control of fractured–porous water-bearing gas reservoirs.

Geological and technological substantiation of waterflooding systems in deposits with hard-to-recover reserves

The study of the process of developing oil reserves in one of the fields with hard-to-recover reserves of the Tournaisian stage of the Volga-Ural oil and gas basin. A significant increase in the oil recovery factor was established when using in-circuit waterflooding as compared to the development of deposits in natural mode. The influence on the degree of reserves recovery is shown by the density of the grid of wells, geological heterogeneity, the sweep efficiency by injection by thickness, variations in the injectivity profile in injection wells. Models are proposed to assess the parameters of the efficiency of waterflooding systems.

Improving the efficiency of terrigenous oil-saturated reservoir development by the system of oriented selective slotted channels

A comparative assessment of variation in the flow rate of oil production wells was performed taking into account increasing of perforated area of the productive part of the rocks, as well as recover of reservoir rocks permeability due to their unloading by creating slotted channels with the method of oriented slotted hydro-sandblast perforation. Different orientation directions and slotting intervals were analyzed, taking into account water encroachment of individual interlayers and azimuth direction of the majority of remaining reserves in separate blocks of the examined formation.&#x0D; In order to estimate development efficiency of terrigenous oil-saturated porous-type reservoirs by means of oriented slotted hydro-sandblast perforation, calculations were performed on a full-scale geological and hydrodynamic model of an oil field in the Perm Region. The object of modeling was a Visean terrigenous productive formation. &#x0D; The modeling of implementing oriented slotted hydro-sandblast perforation was carried out on a 3D filtration model for fourteen marginal wells, located in the zone with excessive density of remaining recoverable reserves and heterogeneous reserve recovery along the section. An optimal layout of slotted channels along the depth of the productive part of the well section was developed. Selective formation of 24 slotted channels was carried out considering the intervals of increased oil saturation. Comparative analysis of estimated flow rate of the wells was performed for cumulative perforation of the examined productive formation and the developed method of slotted perforation. As a result of modeling, an increase in the oil average flow rate of 2.25 t/day was obtained. With oriented slotted hydro-sandblast perforation, incremental cumulative production for two years of prediction calculations per one well reached 0.5 thousand t.

Protective effect of goserelin on ovarian reserve during (neo)adjuvant chemotherapy in young breast cancer patients: a prospective cohort study in China.

Does goserelin, a GnRH agonist, have a protective effect in young breast cancer patients in terms of ovarian reserve markers anti-Müllerian hormone (AMH) and antral follicle count (AFC) during chemotherapy? Compared with chemotherapy alone, concurrent goserelin is associated with a higher probability of ovarian reserve recovery at 1 year after chemotherapy. Previous studies on the administration of goserelin to protect ovarian function during chemotherapy have produced conflicting results because of the endpoint used, namely, chemotherapy-induced amenorrhoea. Reproductive medicine specialists consider AMH and AFC as the most sensitive ovarian reserve markers; however, they have never been used as biomarkers to assess the potential protective effects on ovarian reserve of goserelin during chemotherapy. This was a prospective cohort study in which patients were assigned to receive (neo)adjuvant chemotherapy with goserelin (the goserelin group) or without goserelin (the control group) according to each patient's preference. Of 242 breast cancer patients enrolled between December 2015 and November 2019, 76 in control group and 73 in goserelin group were able to be assessed at 1 year after chemotherapy. Premenopausal patients with a regular menstrual cycle and aged 18-45 years were eligible for enrolment if they were newly diagnosed with stages I-III breast cancer for which treatment with adjuvant or neoadjuvant chemotherapy was planned. Each patient in the goserelin group was given a subcutaneous dose of 3.6 mg at least 1 week before the first cycle of chemotherapy and then every 4 weeks for the duration of chemotherapy. Ovarian reserve markers and menstrual status were evaluated before and after chemotherapy in the two treatment groups. The primary endpoint was the AMH recovery rate, the secondary endpoints were the recovery rates of AFC, estradiol (E2), follicle-stimulating hormone (FSH) and menstruation. Among 149 patients (76 in the control group and 73 in the goserelin group) with complete data at 1 year after chemotherapy, the adjusted recovery rate of AMH was 46.5% and 21.8% in the goserelin group and control group, respectively (odds ratio: 3.08; P = 0.002). The trends in AFC and FSH recovery rates were consistent with that in AMH recovery rate. Notably, AMH levels remained low in 41.3% of patients whose menstrual activity had resumed. Randomisation was not performed because of ethical considerations, so selection bias was inevitable, although propensity score weighting was done. The study was also underpowered because 21.5% (52/242) of enrolled patients received GnRH agonist-containing endocrine therapy and could not be analysed at 1 and 2 years after chemotherapy. Our results indicate that co-administration of goserelin with chemotherapy provides obvious ovarian reserve protection in these young breast cancer patients. We expect that these results will be applicable in clinical practice for young breast cancer patients. This study was funded by the National Key R&D Program of China No. 2016YFC0901302, by the Research and Development Fund of Peking University People's Hospital No. RD2014-13, RDY2017-19 and by AstraZeneca. The authors have no disclosures. NCT02430103.

E&amp;P Notes (January 2021)

E&amp;P Notes (January 2021)

Study of the efficiency of trapped gas displacement by non-hydrocarbon gases from water-flooded gas condensate reservoirs

Analyzing industrial data and the results of theoretical studies, it was found that the natural gas recovery factor in water-drive gas reservoirs is about 50-60%. Considering the significant volumes of residual gas reserves trapped by formation water, there is a need to improve existing development technologies and search for optimal ways to increase hydrocarbon recovery under conditions of intensive water encroaching. Additional researches using hydrodynamic simulations were conducted in order to study the efficiency of enhanced recovery of residual gas reserves by injecting non-hydrocarbon gases into productive reservoirs. Based on the 3D reservoir model, the study of carbon dioxide and nitrogen injection into the initial gas-water contact was carried out in order to slow down the breakthrough of formation water into productive reservoir. The study was performed for different injection duration of carbon dioxide and nitrogen into productive reservoir. According to the results of the statistical processing of the calculated data, the optimal duration of the nitrogen injection was determined to be 8,04 months. The ultimate gas recovery factor for the optimal period of nitrogen injection is 58,11%. At the time of the carbon dioxide breakthrough into production wells, the optimal duration of the carbon dioxide injection was determined to be 16,32 months. The ultimate gas recovery factor for the optimal period of carbon dioxide injection is 61,98 %. Based on a comparative analysis of the efficiency of using various types of non-hydrocarbon gases as injection agents into productive reservoirs, the high efficiency of using carbon dioxide for injection into the initial gas-water contact was established. Due to the solubility of carbon dioxide in formation water, the ultimate gas recovery factor is significantly higher compared to using nitrogen as an injection agent.

Oil Withdrawal Technological Advancement for Multilayer Field

The authors discuss the technology for dual pumping technology of oil-producing wells and show its advantages and shortages. It is concluded that the simultaneous-separate oil production project proposed is economically attractive due to increment in oil production, high income terms and short pay-off period even in small and depleted reservoirs. Furthermore, the potential of the proposed project is evaluated in terms of the required facilities and incremental oil production. Dual pumping technology becomes of ever-more use today, since unified well-spacing pattern envisioned for multilayer fields development and operation ensures feasibility of multiple-zone production, and, as a consequence, ramp-up of reserves recovery and oil drainage amount as well. At the same time, practicability of multiple-zone production depends on a number of fraught factors and requires thereof appropriate inventory and current status analyses to be fulfilled with regard to reserves recovery operations. As influx performance study and fluid-bearing characteristic of reservoirs are often incomplete due to field situation, the authors, therefore, follows the task to carry out an efficiency analysis of multi-zone productions based on dual completion technologies.

Treatment and compliance with virtual reality and anaglyph‐based training programs for convergence insufficiency

BackgroundConvergence insufficiency may be treated by visual exercises designed to increase convergence while maintaining single, clear, binocular vision. However, compliance with treatment is problematic, as patients often cease treatment when symptoms start to improve and before treatment is complete. The purpose of the present study was to assess the feasibility of using gamification of vision training to: (a) treat convergence insufficiency; and (b) improve compliance to treatment in comparison to a conventional treatment over a six‐week treatment period.MethodsTwo interventions, anaglyphs and a virtual reality game of Snakes, were evaluated for their effectiveness in treating adults with convergence insufficiency. The prescribed training regimen was 20-minutes, three times per week for six-weeks. Vision was assessed before and after the treatment period. Participants also filled in the Core Elements of the Gaming Experience Questionnaire to gauge impact of game design on compliance.ResultsEighteen participants (mean age 20.8 ± 1.8-years) met the inclusion criteria for convergence insufficiency and nine participants were randomly assigned to each intervention. Repeated measures analysis of variance showed a significant effect of visit for near point of convergence (F1,16 = 38.32, p < 0.0001), near positive fusional reserves break (F1,16 = 21.94, p < 0.0001) and recovery (F1,16 = 26.87, p < 0.0001), but not of intervention type. Total time played was significantly longer for the virtual reality Snake Game than the anaglyph intervention (p < 0.0001), which translated to mean compliance of 82-per cent and 51-per cent respectively.ConclusionGamification of vision training in a virtual reality environment is feasible and associated with increased compliance, hence may be a useful strategy to treat convergence insufficiency.

Connotations of scientific development of giant gas fields in China

A giant gas field refers to a gas field with proved geological reserves of natural gas more than 30 billion cubic meters, peak annual output of natural gas more than 1 billion cubic meters, and a certain plateau period. It is an important foundation for the rapid growth of China's natural gas reserves and production and its long-term stable development in the future. And it is also the key to ensure the security of gas supply. By systematically analyzing the development practice of more than 260 gas fields at home and abroad and dissecting and simulating typical gas fields, this paper comprehensively studied the connotation, core technology and whole life cycle index system on the scientific development of giant gas fields. It is indicated that the scientific development connotation of giant gas fields consists of the following parts. First, the natural gas development concept with “water identification, control and treatment” as the technical system is put forward. That is to carry out “water-control development” in conventional gas fields and hydraulic fracturing development in unconventional gas fields. A reasonable gas production rate should be set according to the types and characteristics of gas reservoirs. Second, economic and social benefits of gas field development should be evaluated comprehensively to ensure its long-term stable production. Third, the suitable production stabilization mode shall be adopted according to the production characteristics of gas wells and the development characteristics of reservoirs. Fourth, the recoverable reserves of a gas field, the development laws of formation water and artificial water flooding, the ultimate recovery technological countermeasures of the gas field, the cost-effective stable period of the gas field should be determined based on the fine description of conventional and unconventional gas reservoirs in different stages, the development characteristics of gas reservoirs and the monitoring results of production performance. The core technologies in the scientific development of giant gas fields include large-scale optimization technology, scientific well arrangement technology, balanced production technology and deep potential tapping technology. Based on this, several parameters are selected comprehensively as the key indexes for the scientific development of giant gas fields, such as production rate, pressure drop, degree of reserves recovery and output per unit pressure drop, and the whole life cycle index systems for four types of gas reservoirs are established, i.e., high-pressure gas reservoirs, low-permeability and tight gas reservoirs, fractured–porous reservoirs, and shale gas reservoirs. In conclusion, the research results enrich and improve the theories of natural gas development geology and are conducive to guiding the scientific development of different-type giant gas fields, thus further promoting the rapid development of natural gas industry in China.

Improving carbonate rock hardness by consolidating additives to sustain long term fracture conductivity

Fracture conductivity is a fracture's capacity to deliver fluids from the hydrocarbon reservoir to the wellbore. Sustaining long-term fracture conductivity results in better well productivity and reserve recovery. Harder rocks tend to sustain conductivity better than do weak and ductile rocks because they are less likely to suffer from proppant embedment and the crushing and creeping of asperities. This study shows that the hardness of carbonate rocks can be improved significantly when they are treated with carbonate-consolidating chemicals. Ideally, this should be done without damaging the matrix permeability. This research tested the capacity of microemulsion, calcium hydroxide (Ca(OH)2) nanoparticles, and tetraethyl orthosilicate (TEOS) to consolidate carbonate rocks. These are all believed to improve rock hardness by enhancing carbonate grain attachment. The treatments were applied to cores and slabs of Mississippian Indiana limestone and permo-carboniferous Khuff carbonate rocks. These chemicals were tested by either impregnation or complete immersion of the rock sample in a solution. SEM, X-ray fluorescence, porosity, permeability, and rock hardness were all measured before after the treatment. It was observed that the rock surface Young's modulus could be improved by 10%–38%. Matrix permeability was reduced by 50% when Ca(OH)2 nanoparticles were tested. Nevertheless, the TEOS improved the carbonate rock's hardness and permeability 18% and 44%, respectively. A modeling study has also been provided to explain the impact of fractured rock strengthening on productivity improvement.

IMPACT OF ADJUVANT CHEMOTHERAPY OR TAMOXIFEN ALONE ON THE OVARIAN RESERVE OF YOUNG WOMEN WITH BREAST CANCER: A PROSPECTIVE LONGITUDINAL STUDY

To determine the longitudinal impact of adjuvant chemotherapy and tamoxifen-only treatments on the ovarian reserve recovery patterns of women with breast cancer by using a ultra-sensitive Anti-Mullerian Hormone (AMH) assay.

АНАЛИЗ МИРОВОГО ОПЫТА ПРИМЕНЕНИЯ ТЕХНОЛОГИЙ ВЫРАВНИВАНИЯ ПРОФИЛЕЙ ПРИЕМИСТОСТИ НА ОСНОВЕ СШИТЫХ ПОЛИМЕРНЫХ ГЕЛЕЙ

Due to a growing number of wells being in late stages of operation, there is an increasing demand for introduction of new integrated solutions reducing wellbore fluid watercut. Eventually, watercut reduction enables a prolonged operation of encroached wells and improves recovery of residual oil reserves. Polyacrylamide is the most available and industrially applicable reagent stabilizing formation water intake profiles. Based on the review of international and native experience, the study analyses the effectiveness of a variety of methods using polyacrylamide to reduce the wellbore fluid watercut. The paper discusses such injection technologies as conventional polymer water flooding, in situ gels, colloidal dispersion gels, and precrosslinked gels. Cross-linked polymer gels are three-dimensional structures where polymer chains are cross-linked by either ionic or covalent polar bonds. Depending on particle sizes, they are divided into macrogels (100 μm to several cm) and microgels (0.1 to 30 μm). Compared to in situ compounds, the use of macro- and microgels substantially reduces the risk of polymer chain destruction by mechanical, chemical or thermal factors. Based on the analysis, recommendations were developed for application of various polymer injection methods taking into account the geological and technological conditions of the production site development. It is recommended to use macrogels to reduce the wellbore fluid watercut in fields with the reservoir permeability above 500 mD; while it is advisable to use microgels with the reservoir permeability from 100 to 500 mD; and colloidal dispersion gels can be used with the reservoir permeability from 10 to 100 mD. In order to improve the development effectiveness, advanced technologies need to be adapted in due time to the geological and process conditions. Also pilot production operations need to be conducted in the native fields.

Impact of breast cancer chemotherapy on ovarian damage and recovery.

e24059 Background: As societal shifts have led to more women delaying childbearing, a diagnosis of breast cancer is increasingly more likely to occur prior to the completion of family building. Therefore, understanding impact of chemo on future fertility is of the utmost importance. This study evaluates the trends in AMH over time in women receiving different chemo regimens for breast cancer. Methods: This is an IRB approved prospective study of 164 women, &lt; 45 years old with non-metastatic breast cancer who were enrolled at time of diagnosis. Patients received chemo and had prospective serum AMH measured at baseline,12, 18 &amp; 24 mos post-chemo. Of those, 99/164 completed 2-yr follow up. Pts were divided according to their chemotherapy regimen: ddAC-T, CMF and other (e.g. TH). Results: Mean age in ddAC-T (n = 118), CMF (n = 22) and other (n = 23) chemo groups were 37.1±4.6, 41.1±3.2 and 37.6±4.3 yrs, respectively (p = 0.001). AMH sharply declined between baseline &amp; 12 mos post-chemo in all groups (p = 0.005). There was no difference in rate of decline between the groups, after adjusting for age. Age was an important predictor of AMH. Older age at study entry was associated with lower AMH with a decrease of 9% per life year (p = 0.0005). AMH recovered from 12 to 18 mos post-chemo in all groups. 18 mos after chemo, AMH recovery was observed in 61%, 59% &amp; 65% in ddAC-T, CMF &amp; other groups, respectively. In the ddAC-T arm there was a 1.9 fold increase in AMH while there was a 1.4 and 3.3 fold increase in the CMF and other arms, respectively. At 2-yrs post-chemo, AMH recovery rate reached 67%, 69% &amp; 77% in ddAC-T, CMF &amp; other groups, respectively. However, 12% in ddAC-T and 23% in CMF had undetectable AMH. Baseline AMH was 1.59 fold higher in pts whose AMH increased compared to those whose AMH decreased between 12 &amp; 18 mos (p = 0.035). AMH recovery was associated with higher baseline AMH. Age, BMI &amp; chemo type did not correlate with AMH recovery and tamoxifen treatment did not impact AMH recovery. Conclusions: Our data show that anthracycline plus taxane, taxane-based and CMF chemo regimens compromise ovarian reserve in breast cancer patients in similar fashion. As surviving ovarian follicles resume production of AMH, most of ovarian reserve recovery occurs by 18 mos post-chemo with some minor recovery from 18-24 mos. Baseline AMH level is the most important predictor of AMH recovery. Hence in women undergoing gonadotoxic chemo, ovarian reserve should be assessed by AMH before and 12 months after treatment to determine extent of damage. The novel information provided in this study is valuable for counseling cancer pts about fertility preservation. Clinical trial information: NCT00823654 .

Recognition of turbidite stages in the Massapê oil field, Recôncavo Basin - Brazil, using well logs

The integration of rock and well logs data is fundamental for the interpretation of depositional systems and sequences, a fundamental support for E&P activities. This approach was applied on the low permeability turbidite sandstones and slurries of the Maracangalha Formation, in the Massapê Oil/Gas Field, Recôncavo Basin. Well-log interpretation allowed the recognition of 23 turbidite stages, each of which records a specific period of growth of a fan system. These stages are composed of four main facies, all observed in each one of these stages: (a) fine to medium sandstones, with porosities greater than 9%, being the best reservoirs; (b) silty to very fine sandstone slurry facies, that corresponds to very muddy reservoirs with porosities less than 9%, forming important permeability barriers; (c) siltstones and (d) shales. Turbidite stages appear in the Gamma Rays logs (GR) with funnel, block and serrated log motif patterns, corresponding to dominantly thinning and fining upward signatures, recognized in several wells in the Massapê Field. The detailed correlation of these well-logs showed that these stages are present in the whole field. The mapping of high resolution turbiditic stages, considering the correlation of their four facies, will allow a better location of wells, resulting in a more efficient exploration and production development, capable of increasing the recovery of important oil reserves that still exist in the area, optimizing costs and giving greater robustness to E&P processes.