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Waterdrive (or water drive) petroleum reservoirs are characteristically bounded by and in communication with aquifers. As pressure decreases during pressure depletion, the compressed waters within the aquifers expand and overflow into the petroleum reservoir. The invading water helps drive the oil to the producing wells, leading to improved oil recoveries. Like gas reinjection and gas cap expansion, water influx also acts to mitigate the pressure decline. The degree to which water influx improves oil recovery depends on the size of the adjoining aquifer, the degree of communication between the aquifer and petroleum reservoir, and ultimately the amount of water that encroaches into the reservoir.
This page briefly describes some of the field applications of resin treatment for conformance improvement. Littlefield, Fader, and Surles reports on 26 production wells of the Kern River and San Ardo fields that were treated in 1990 and 1991 with furan resin jobs in which the treated production wells were suffering from water-encroachment problems. Most (24) of the wells were in the heavy oil Kern River field of the Lower San Joaquin Valley in California. When the furan resin treatments were applied, the Kern River field was undergoing steamflooding. Of the production wells treated, 79% showed significant reductions in water production after the treatments.
Izadi, Mohammad (Louisiana State University) | Nguyen, Phuc H. (Louisiana State University) | Fleifel, Hazem (Louisiana State University) | Maestre, Doris Ortiz (Ecopetrol) | Kam, Seung I. (Louisiana State University)
Summary While there are a number of mechanistic foam models available in the literature, it still is not clear how such models can be used to guide actual field development planning in enhanced oil recovery (EOR) applications. This study aims to develop the framework to determine the optimum injection condition during foam EOR processes by using a mechanistic foam model. The end product of this study is presented in a graphical manner, based on the sweep-efficiency contours (from reservoir simulations) and the reduction in gas mobility (from mechanistic modeling of foams with bubble population balance). The main outcome of this study can be summarized as follows: First, compared to gas/water injection with no foams, injection of foams can improve cumulative oil recovery and sweep efficiency significantly. Such a tendency is observed consistently in a range of total injection rates tested (low, intermediate, and high total injection rates Qt). Second, the sweep efficiency is more sensitive to the injection foam quality fg for dry foams, compared to wet foams. This proves how important bubble-population-balance modeling is to predict gas mobility reduction as a function of Qt and fg. Third, the graphical approach demonstrates how to determine the optimum injection condition and how such an optimum condition changes at different field operating conditions and limitations (i.e., communication through shale layers, limited carbon dioxide (CO2) supply, cost advantage of CO2 compared to surfactant chemicals, etc.). For example, the scenario with noncommunicating shale layers predicts the maximum sweep of 49% at fg = 55% at high Qt, while the scenarios with communicating shale layers (with 0.1-md permeability) predicts the maximum sweep of only 40% at fg = 70% at the same Qt. The use of this graphical method for economic and business decisions is also shown, as an example, to prove the versatility and robustness of this new technique.
Abstract Accurate oil production monitoring is essential for scheduling well work and optimizing the economic performance of primary and enhanced recovery projects. The significance of water cut monitoring accuracy on oil rate determination is discussed and illustrated. This paper provides a comprehensive uncertainty analysis of several water cut monitoring methods commonly employed by oil field operators. These include liquid sampling, capacitance, microwave, ultrasonic, spectroscopy and density methods. The basic operating principles of each monitoring method are described and measurement uncertainty analysis procedures are employed to identify key parameters that affect the overall accuracy of each water cut monitoring method. The analysis results provide useful accuracy assessments that can be used in water cut meter selection, field testing and implementation.
Abstract Controlling excessive water production in mature oil fields has always been one major objective of the oil and gas industry. This objective calls for planning of more effective water-control treatments with optimized designs to obtain more attractive outcomes. Unfortunately, planning such treatments still represents a dilemma for conformance experts due to the lack of systematic design tools in the industry. This paper proposes and makes available a new design approach for bulk gel treatments by grouping designs of 62 worldwide field projects (1985-2018) according to gel volume-concentration ratio (VCR). After compiling them from SPE papers, the average gel volumes and polymer concentrations in the field projects were used to evaluate the gel VCR. Distributions of field projects were examined according to the gel VCR and the formation type using stacked histograms. A comprehensive investigation was performed to indicate the grouping criterion and design types of gel treatments. Based on mean-per-group strategy, the average VCR was estimated for each channeling and formation type to build a three-parameter design approach. Two approximations for the average polymer concentration and two correlations for minimum and maximum designs and were identified and included in the approach. The study shows that the gel VCR is a superior design criterion for in-situ bulk gel treatments. Field applications tend to aggregate in three project groups of clear separating VCR cut-offs (<1, 1-3, >3 bbl/ppm). The channeling type is the dividing or distributing criterion of the gel projects among the three project groups. We identified that VCRs<1 bbl/ppm are used to treat conformance problems that exhibit pipe-like channeling usually presented in unconsolidated and fractured formations with very long injection time (design type I). For fracture-channeling problems frequently presented in naturally or hydraulically-fractured formations, VCRs of 1-3 bbl/ppm are used (design type II). Large gel treatments with VCR>3 bbl/ppm are performed to address matrix-channeling often shown in matrix-rock formations and fracture networks (design type III). Results show that the VCR approach reasonably predicts the gel volume and the polymer concentration in training (R of 0.93 and 0.67) and validation (AAPE <22%) samples. Besides its novelty, the new approach is systematic, practical, and accurate, and will facilitate the optimization of the gel treatments to improve their performances and success rate.
Abstract This study designs a novel complex fluid (foam/emulsion) using as main components gas, low-toxicity solvents (green solvents) which may promote oil mobilization, and synergistic foam stabilizers (i.e. nanoparticles and surfactants) to improve sweep efficiency. This nanoparticle-enabled green solvent foam (NGS-foam) avoids major greenhouse gas emissions from the thermal recovery process and improves the performance of conventional green solvent-based methods (non-thermal) by increasing the sweep efficiency, utilizing less solvent while producing more oil. Surfactants and nanoparticles were screened in static tests to generate foam in the presence of a water-soluble/oil-soluble solvent and heavy crude oil from a Canadian oil field (1600 cp). The liquid phase of NGS-foam contains surfactant, nanoparticle, and green solvent (GS) all dispersed in the water phase. Nitrogen was used as the gas phase. Fluid flow experiments in porous media with heterogeneous permeability structure mimicking natural environments were performed to demonstrate the dynamic stability of the NGS-foam for heavy oil recovery. The propagation of the pre-generated foam was monitored at 10 cm intervals over the length of porous media (40 cm). Apparent viscosity, pressure gradient, inline measurement of effluent density, and oil recovery were recorded/calculated to evaluate the NGS-foam performance. The outcomes of static experiments revealed that surfactant alone cannot stabilize the green solvent foam and the presence of carefully chosen nanoparticles is crucial to have stable foam in the presence of heavy oil. The results of NGS-foam flow in heterogeneous porous media demonstrated a step-change improvement in oil production such that more than 60% of residual heavy oil was recovered after initial waterflood. This value of residual oil recovery was significantly higher than other scenarios tested in this study (i.e. GS- water and gas co-injection, conventional foam without GS, GS-foam stabilized with surfactant only and GS-waterflood). The increased production occurred because NGS-foam remained stable in the flowing condition, improves the sweep efficiency and increases the contact area of the solvent with oil. The latter factor is significant: comparing to GS-waterflood, NGS-foam produces a unit volume of oil faster with less solvent and up to 80% less water. Consequently, the cost of solvent per barrel of incremental oil will be lower than for previously described solvent applications. In addition, due to its water solubility, the solvent can be readily recovered from the reservoir by post flush of water and thus re-used. The NGS-foam has several potential applications: recovery from post-CHOPS reservoirs (controlling mobility in wormholes and improving the sweep efficiency while reducing oil viscosity), fracturing fluid (high apparent viscosity to carry proppant and solvent to promote hydrocarbon recovery from matrix while minimizing water invasion), and thermal oil recovery (hot NGS-foam for efficient oil viscosity reduction and sweep efficiency improvement).
Summary In recent years, the advancement of horizontal-well technology has played a major role in making oil production economically feasible from many reservoirs. One of the major problems that can reduce the efficiency of using horizontal wells is gas and water coning caused by the heel-toe effect and heterogeneity along the well. To tackle this problem, Equinor’s autonomous inflow-control device (ICD) (AICD), known as rate-controlled production (RCP) valves, is widely used today. RCP valves can effectively delay the early water breakthrough and partially choke back water autonomously after water breakthrough. To fulfill a suitable design of a long horizontal well with the RCP completion, a detailed understanding of multiphase-flow behavior from the reservoir pore to the wellbore and production tubing is needed. Coupling a dynamic multiphase-flow simulator such as the OLGA (Schlumberger Limited, Sugar Land, Texas, USA) simulator with the near-wellbore reservoir module such as the OLGA ROCX module provides a robust tool for achieving this purpose. However, there is no predefined option in the OLGA simulator for implementing the autonomous behavior of the RCP valves directly. Therefore, creating a model of oil production by considering well completion with the RCP valves in the OLGA simulator is challenging. In the previous works, this has been performed by using the Proportional Integral Derivative (PID) Controller option in the OLGA simulator, which controls the opening of an equivalent orifice valve according to the fixed value of the water cut. However, because of the performance of the PID Controller using a fixed setpoint and the difficulties in properly tuning the PID Controller, choosing this option leads to a large degree of inaccuracy in the simulation models. In this paper, by proposing a novel method with a developed mathematical model and a control function for the RCP valves, the autonomous behavior of these valves is implemented in the OLGA simulator. In this new approach, the control signals are calculated using the variation of water cut and introduced to the OLGA simulator through the Table Controller option instead of the PID Controller. The presented approach in this paper can be used for the simulation of water-cut (or gas/oil-ratio) reduction potential of all RCP-type AICDs in reservoirs with different characteristics. However, to explain the procedure of this approach in detail, the near-well oil production from Well 16/2-D-12 in the Johan Sverdrup Field (JSF) considering RCP completion is modeled as a case study. In this study, the simulation model is developed using one of the commonly used types of RCP valves called the TR7 RCP valve. Version 2016.1.1 of the OLGA simulator/ROCX module is used (Schlumberger 2016). According to the simulation results, compared with using ICDs, by the completion of Well 16/2-D-12 with RCPs, the water cut, water-flow rate, and accumulated water production can be reduced by 2.9, 13.3, and 12.1%, respectively, after 750 days. The results also showed that by using the proposed approach, the autonomous behavior of the RCP valves according to the water-cut variations can be appropriately implemented in the OLGA simulator. This can help engineers and researchers to achieve a better design of a long horizontal well using the RCP completion. Consequently, using this approach can be beneficial for improving technology, optimizing production, minimizing risk, and reducing costs in oil recovery.
Abstract One of the major brownfields in offshore India was producing for three decades from main carbonate reservoirs of the Eocene and Oligocene age. Average production of this brownfield is approximately 11,000 barrels of oil per day (BOPD). To maintain the declining reservoir pressure, the field has been under active water injection for more than two decades. However, being a complex carbonate reservoir with high textural heterogeneity, the water-front movement is not very well understood and monitored. To increase the oil production, the operator started drilling horizontal drain-holes from the platforms and has adopted a conventional perforated and blind tubing combination as a completion strategy. However, it was found that wells were performing poorly with very high water cut. An integrated and comprehensive petrophysical workflow was applied that used data analysis and the added value of advanced 3D acoustic data in combination with nuclear magnetic resonance (NMR) data to provide a rapid realistic solution to avoid such high watercut through optimizing the completion strategy. This led to a production gain in this offshore field, which was underperforming as per earlier predictions and expectations. Conventional well-log based qualitative evaluation for horizontal segmentation strategy was rejected in favor of an integrated approach for lateral reservoir facies delineation. Lateral petrophysical property characterization was carried out through quick integration of NMR pore-size driven facies analysis, advanced acoustic radial profiling, anisotropy, and Stoneley analysis. Permeability profiling along the horizontal drain-hole section using NMR and acoustics provided critical insight. Those were integrated to avoid potential high permeability conduits of thief zones for water breakthrough. A rock-quality index was derived to optimize the completion strategy soon after the logging, even preceding the rig-down of the acquisition runs and lowering of the completion. Zones with higher skin, deeper formation damage, and lower rock-mechanical properties were avoided for efficient swell-packer placements. The well started producing and continued production with only 10% water cut along with 450 barrels of oil compared to an average 90% watercut and 100 barrels of oil from the other wells of the same platform, which used the older nonoptimized completion strategy. Based on the promising result for the first well, the same workflow was used for two similar wells of other two different platforms inthe same field, which also resulted in similar production with enhanced oil production and reduced water cut. The study using the rapid integrated evaluation workflow established efficient zonal isolation of high permeability thief zones with accuracy for timely optimization of horizontal well segmentation, which assisted in pulling higher production in this brownfield by reducing unwanted water production.
Yue, Baolin (Tianjin Branch of CNOOC, China Co., Ltd) | Liu, Bin (Tianjin Branch of CNOOC, China Co., Ltd) | Shi, Hongfu (Tianjin Branch of CNOOC, China Co., Ltd) | Shi, Fei (Tianjin Branch of CNOOC, China Co., Ltd) | Zhang, Wei (Tianjin Branch of CNOOC, China Co., Ltd)
Abstract The prediction of reservoir fluid production law play a key role in offshore oil field development plan design. It determines the parameter selection of pump displacement, oilfield submarine pipe capacity, platform fluid handling capacity, power generation equipment, etc. If the liquid production forecast is too low, the capacity will be expanded later, while if the forecast is too high, it will result in a waste of investment, which directly affects the fixed investment in oilfield development. Based on the statistical analysis of big data, this paper applies the dynamic data of all single wells and full life cycle of the oil field to analyze the dimensionless liquid production index (DLPI) law, and further establish the liquid production index prediction formula on this basis. Thus, the different types of Bohai plate and statistical table of the characteristics of the DLPI of the reservoir are completed. The results show that the DLPI of Bohai Sea heavy oil reservoir are following: water cut < 60 % indicates the trend is flat; water cut between 60 ∼ 80 % illustrates the slow growth (water cut 80 % is 2.5∼3 times); water cut > 80 % shows rapid growth (water cut 95% is 5.5∼6 times). The DLPI of Bohai Sea conventional oil reservoir are as following: when the water cut < 60%, the DLPI drops first, and then increase when the water cut is about 30% (the lowest point (0.7∼0.9 times)). When the water cut rise to 60%, the DLPI returns to 1 times; When the water cut is 60∼80%, it grows slowly (1.5∼2 times); when the water cut > 80 %, it grows rapidly (water cut 95% is 2∼3 times). The study may provide a guidance to the prediction of the amount of fluid in offshore oilfields, provide a basis for the design of new oilfield development schemes and increasing the production of old oilfields.