Numerical modeling of self-potential in heterogeneous reservoirs

Monitoring water movement toward production wells through downhole measurements of self-potential (SP) was a promising new technology. However, there were uncertainties about its applicability in heterogeneous, multilayered reservoirs. Using numerical modeling, we investigated the likely magnitude and behavior of SP during oil production supported by water injection in two different models of such reservoirs. We found that the magnitude of the SP signal that would be measured along a production well increased as water approached the well, exceeding an assumed noise level of 0.1 mV before water breakthrough. We also found that, in the reservoir models tested, the maximum value of SP at the well skewed toward the fastest waterfront before water breakthrough. The trend of SP increasing at the well with time, together with the shape of the SP profile, were the prime indicators used to investigate water movement. In the reservoir models tested, before water breakthrough the fastest approaching waterfront could be detected approximately 20 m away from the well. However, subsequent waterfronts approaching the well in other layers could not be detected before breakthrough. The effect of these later waterfronts on the SP profile at the well was only detectable at breakthrough. We attributed this to the fact that the SP generated in these layers is masked by the high SP created by the fastest waterfront. Our findings emphasized the importance of an enhanced understanding of reservoir geology and rock electrical properties for better prediction and interpretation of SP.

High-resolution pressure transducer design and associated circuitry to build a network-ready smart sensor for distributed measurement in oil and gas production wells

Miniaturized single-mode thickness-shear pressure transducer combined with high-temperature SOI, silicon on insulator, integrated circuit technology is proposed as network-ready high-pressure high-resolution smart sensor for distributed data acquisition in oil and gas production wells. The transducer miniaturization is investigated with a full 3D computer model previously developed by the authors to assess the impact of intrinsic losses and various geometrical features on transducer performance. Over the last decades there has been a trend toward size reduction of high-resolution pressure transducer. The implemented model provides insight into the evolution of high-resolution pressure transducers from Hewlett-Packard™ to Quartzdyne™ and beyond. Distributed measurement in production oil wells in extreme harsh environment, such as found in the pre-salt layer, is an unsolved problem. The industry move toward electrified wells offers an opportunity for application of smart sensor technology and power line communications to achieve distributed high-resolution data acquisition.

MODEL-BASED OPTIMIZATION OF CYCLES OF CO2 WATER-ALTERNATING-GAS (CO2-WAG) INJECTION IN CARBONATE RESERVOIR

Pre-salt reservoirs are among the most important discoveries in recent decades due to the large quantities of oil in them. However, high levels of uncertainties related to its large gas/CO2 production prompt a more complex gas/CO2 management, including the use of alternating water and gas/CO2 injection (WAG) as a recovery mechanism to increase oil recovery from the field. The purpose of this work is to develop a methodology to manage cycle sizes of the WAG/CO2, and analyze the impact of other variables related to the management of producing wells during the process. The methodology was applied to a benchmark synthetic reservoir model with pre-salt characteristics. We used five approaches to evaluate the optimum cycle size under study, also assessing the impact of the management of producing wells: (A) without closing producers due to gas-oil ratio (GOR) limit; (B) GOR limit fixed at a fixed value (1600 m³/m³) for all wells; (C) GOR limit optimized per well; (D) joint optimization between GOR limit values of producers and WAG cycles; and (E) optimization of the cycle size per injector well with an optimized GOR limit. The results showed that the optimum cycle size depends on the management of the producers. Leaving all production wells open until the end of the field's life (without closing based on the GOR limit) or controlling the wells in a more restricted manner (with closing based on the GOR limit), led to significant variation of the results (optimal size of the WAG/CO2 cycles). Our study, therefore, demonstrates that the optimum cycle size depends on other control variables and can change significantly due to these variables. This work presents a study that aimed to manage the WAG-CO2 injection cycle size by optimizing the life cycle control variables to obtain better economic performance within the premises already established, such as the total reinjection of gas/CO2 produced, also analyzing the impact of other variables (management of producing wells) along with the WAG-CO2 cycles.

Facies Analysis and Paleoenvironmental Assessment of the Upper Campanian Hartha Formation in Y and J Fields Northwestern Zagros Basin, Iraq

The Upper Campanian Hartha Formation represents potential Cretaceous hydrocarbon-bearing reservoir rocks across the Y and J oilfields northwestern Zagros Basin, northern Iraq. The study objective is depositional environment which affects reservoir properties by tool, lithofacies, core, thin section, and logs, using petrel (V.2016) and strat software, facies distribution, grains, and diagenetic processes control and enhance reservoir properties which can plan platform production and minimize risks in choosing production wells location at two fields scale The current study is concerned with lithofacies and microfacies of the Hartha Formation within two fields in northern Iraq. Several subsurface well-log data, core, and cutting samples have been used in order to prepare thin sections that were subjected to sedimentological (lithofacies, and grain-size) examination. The petrography investigation revealed five rock-units including Hr. 1, 2, 3, 4, and 5, the thickness of 89 m in the Y-A field and increasing to up to 140 m in the J-B field might be due to erosion or tectonic uplift of the topography in Y subbasin. Which is locally sub-basin within study fields western banks of Tigris river as gentle slope ramp depositional condition with Spectrum microfacies from lime-mudstone to packstone texture with rudest and benthic debris enhances by diagenesis, dolomitization, dissolution moldic porosity, fracture; dolostone is more effective in the upper section of the formation in A than B Wells. Many factors, such as cementation, compaction, and pore-filling autogenic minerals, decrease reservoir quality, and their effects are similar in wells A and B.

The geosolitonic concept of high output hydrocarbon deposits formation

Based on the well-known results of studies of the ether-geosoliton concept of the growing Earth, the article presents the conclusions that made it possible to propose a model of thermonuclear synthesis of chemical elements that form renewable reserves of developed oil and gas fields. It was revealed that local zones of abnormally high production rates of production wells and, accordingly, large cumulative production at developed fields in Western Siberia are due to the restoration of recoverable reserves due to geosoliton degassing. Therefore, when interpreting the results of geological and geophysical studies, it is necessary to pay attention to the identified geosoliton degassing channels, since in the works of R. M. Bembel and others found that they contributed to the formation of a number of hydrocarbon deposits in Western Siberia. When interpreting the results of geological-geophysical and physicochemical studies of the fields being developed, it is recommended to study the data of the ring high-resolution seismic exploration technology in order to identify unique areas of renewable reserves, which can significantly increase the component yield of hydrocarbon deposits.

Uncertainty in Geomechanical Modeling

The active application of geomechanical modeling in the oil and gas industry began in the early 2000s. Geomechanics is used in all life cycles of the field-from exploration drilling to field development models, construction of production wells and monitoring of the development process. The success of geomechanical modeling directly depends on the quantity and quality of input information. In contrast to the geological and hydrodynamic models in geomechanics, there is still no common approach and algorithm for the quantitative determination of the error of the model. This paper presents an algorithm for determining the 1D error of a geomechanical model, taking into account the measurement errors of the devices and the correlation dependencies used. This is the first step towards the formation of a unified approach to the quantitative determination of the error of 1D and 3D geomechanical models and the construction of uncertainty corridors. In this paper, we propose a mechanism for estimating the error of correlation dependencies, which includes not only the error of the measuring equipment, but also the resulting convergence of the dependence and the rate of growth or decline of this convergence. The confidence parameter is used to estimate the contribution of a particular dimension to the calculations. The sensitivity of the resulting error to the quality of the source information is analyzed. In the application of this technique, it is possible at the initial stage to make a conclusion about the quality of the simulation results and to take measures to improve the reliability of the calculations.

Field Realization of Adaptive Reservoir Simulation for Steam Injection Forecasting

Globally, steam injection for heavy and high-viscous oil recovery is increasing, including carbonate reservoirs. Lack of full understanding such reservoir heating and limited information about production and injection rates of individual wells require to forecast steam injection not only deterministic and simple liquid displacement characteristic modeling types, but also the data-driven one, which covers the adaptive modeling. The implementation and validation of the adaptive system is presented in this paper by one of the world's largest carbonate reservoirs with heavy and high-viscous oil of the Usinsk field. Steam injection forecasting in such reservoirs is complicated by the unstable well interactions and relatively low additional oil production. In the adaptive geological model, vertical dimensions of cells are similar to gross thicknesses of stratigraphic layers. Geological parameters of cells with drilled wells do not necessarily match actual parameters of those wells since the cells include information of neighboring wells. During the adaptive hydrodynamic modeling, a reservoir pressure is reproduced by cumulative production and injection allocation among the 3D grid cells. Steam injection forecasting is firstly based on the liquid displacement characteristics, which are later modified considering well interactions. To estimate actual oil production of steamflooding using the reservoir adaptive geological and hydrodynamic models, dimensionless interaction coefficients of injection and production wells were first calculated. Then, fuzzy logic functions were created to evaluate the base oil production of reacting wells. For most of those wells, actual oil production was 25 – 30 % higher than the base case. Oil production of steamflooding for the next three-year period was carried out by modeling two options of the reservoir further development - with and without steam injection. Generally, forecasted oil production of the option with steam injection was about 5 % higher. The forecasting effectiveness of cyclic steam stimulations of production wells was done using the cross-section method, when the test sample was divided into two groups - the best and the worst, for which the average forecasted oil rates after the stimulations were respectively higher or lower than the average actual oil rate after the stimulations for the entire sample. The difference between the average actual oil rates after the stimulations of the best and the worst groups was 32 %, i.e. this is in how much the actual oil production could have increased if only the best group of the sample had been treated.

Comparison of Water Treatment Plant and Water Source Well: Field Evaluation of Waterflooding Project in Shushufindi-Aguarico Field

Waterflooding project has been implemented in Shushufindi-Aguarico mature field since late 2014. Having a compatible and cost-effective injected water is one of the key elements to ensure the success of this project. In perspective, water treatment plant was constructed in 2014 during pilot stage while water sources wells were completed in 2019 as an alternative source of injected water at the expansion stage of waterflooding project. This paper presents the comparison between both systems used as part of the water injection strategy: the Water Injection Plant (WIP) and Water Producer Wells (WPW). A complete system of water treatment plant is located in one of the production stations. The process basically starts by collecting water from production wells and workovers then treating it mechanically using a flotation unit and chemically to remove solid as well as oil contents. The water is then injected into injection wells with the help of horizontal pumping system (HPS). In the system of water source wells, two wells were converted to produce water from Hollin water reservoir utilizing electrical submersible pumps (ESP). The water is directly injected without any treatment into injection wells given the analysis of its fluid properties. The initial investment for water treatment plant is four times compared to water source well providing equal injection capacity where the operational cost per barrel of injected water is similar. The operational cost for water treatment plant refers to surface facilities maintenance and daily chemical consumption while for water source well it refers to associated cost of ESP reparation and workover operation. The average run-life of the water source wells in Ecuador Oriente basin is 1,200 days. The biggest challenge of water treatment plant is dealing with solid content whereas for water source well is on how to ensure integrity of the well and the flowline system in the high temperature and CO2 environment. Continuous improvements have been performed to address these challenges such as chemical treatment adjustments, real-time surveillance of injection wells, and modification of flowline system. Water treatment plant not only provides compatible water for injection wells but also supports water handling capacity as it utilizes water from production wells. In the other hand, compatible and clean water from Hollin water reservoir is the main benefit of water source wells. This paper will outline the pros and cons of water treatment plant and water source well based on field evaluation in Shushufindi-Aguarico field. It outlines the operational experience and lessons learned that can be used as a guide and reference when evaluating water sources for a waterflooding strategy. Economical analysis as well as continuous improvement will also be presented in this paper to deliver an integrated analysis.

Challenges of Gas Wells Killing Operation with Emphasis on Reservoir & Completion Integrity Issues

Well killing always remains a most radical part during the life cycle of gas production wells with reservoir and completion integrity issues. In moderate permeability gas reservoirs, it will be more challenging due to below issues; Low pressure gas reservoir with moderate reservoir permeability where hydrostatic head of water is almost double the formation pressure Well with the sustainable annulus pressures (Production & first cemented annulus) Well with complex layered scale / asphalting deposition Completion jewelry component integrity breached Recycle reservoir with pressure maintenance Noise logs / corrosion logs generally conducted in order to assess the downhole completion jewelry and potential leak source prior any attempt for killing the well. To achieve the desired accessibility extensive scale analysis for better designing of scale clean out operation carried out specially to access the SPM. Variation of reservoir permeability considered for designing of optimized kill fluid for Depleted horizontal gas reservoir to cater challenge of complete losses. Effective fluid loss solutions designed and implemented to avoid abnormal fluid losses. Further more Polymer based gels used to kill and prevent the gas peculation to surface. Wells having completion and reservoir integrity issue isolated by considering cement zonal isolation, salt plugs, thru-tubing bridge plugs and nipple less plugs. All these barriers having their advantages and disadvantages with reference to work over objectives and their application limitations with respect to well conditions and detail study conducted for each candidate prior execution. Depletion Gas well killing and securing operation considered to be complex in nature and may result serious concern of rig intervention or well future objectives in case of improper execution. Gas wells having reservoir integrity issues and in case of 1st cemented Annulus pressure can be isolated by using thru-tubing bridge plugs. For retrieval of dummy from SPM must be done after setting of downhole plug to avoid any heavy suction for wire line operation. Cement plug operation is not suitable for such wells due to severe losses and fluid circulation limitation. Adequate selection of kill gel fluid as per reservoir characteristics will improve the killing efficiency.