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.

An Innovated Water Shutoff Technology in Offshore Carbonate Reservoir

The problem of water production in carbonate reservoir is always a worldwide problem; meanwhile, in heavy oil reservoir with bottom water, rapid water breakthrough or high water cut is the development feature of this kind of reservoir; the problem of high water production in infill wells in old reservoir area is very common. Each of these three kinds of problems is difficult to be tackled for oilfield developers. When these three kinds of problems occur in a well, the difficulty of water shutoff can be imagined. Excessive water production will not only reduce the oil rate of wells, but also increase the cost of water treatment, and even lead to well shut in. Therefore, how to solve the problem of produced water from infill wells in old area of heavy oil reservoir with bottom water in carbonate rock will be the focus of this paper. This paper elaborates the application of continuous pack-off particles with ICD screen (CPI) technology in infill wells newly put into production in brown field of Liuhua, South China Sea. Liuhua oilfield is a biohermal limestone heavy oil reservoir with strong bottom water. At present, the recovery is only 11%, and the comprehensive water cut is as high as 96%. Excessive water production greatly reduces the hydrocarbon production of the oil well, which makes the production of the oilfield decrease rapidly. In order to delay the decline of oil production, Liuhua oilfield has adopted the mainstream water shutoff technology, including chemical and mechanical water shutoff methods. The application results show that the adaptability of mainstream water shutoff technology in Liuhua oilfield needs to be improved. Although CPI has achieved good water shutoff effect in the development and old wells in block 3 of Liuhua oilfield, there is no application case in the old area of Liuhua oilfield which has been developed for decades, so the application effect is still unclear. At present, the average water cut of new infill wells in the old area reaches 80% when commissioned and rises rapidly to more than 90% one month later. Considering that there is more remaining oil distribution in the old area of Liuhua oilfield and the obvious effect of CPI in block 3, it is decided to apply CPI in infill well X of old area for well completion. CPI is based on the ICD screen radial high-speed fluid containment and pack-off particles in the wellbore annulus to prevent fluid channeling axially, thus achieving well bore water shutoff and oil enhancement. As for the application in fractured reef limestone reservoir, the CPI not only has the function of wellbore water shutoff, but also fills the continuous pack-off particles into the natural fractures in the formation, so as to achieve dual water shutoff in wellbore and fractures, and further enhance the effect of water shutoff and oil enhancement. The target well X is located in the old area of Liuhua oilfield, which is a new infill well in the old area. This target well with three kinds of water problems has great risk of rapid water breakthrough. Since 2010, 7 infill wells have been put into operation in this area, and the water cut after commissioning is 68.5%~92.6%. The average water cut is 85.11% and the average oil rate is 930.92 BPD. After CPI completion in well X, the water cut is only 26% (1/3 of offset wells) and the oil rate is 1300BPD (39.6% higher than that of offset wells). The target well has achieved remarkable effect of reducing water and increasing oil. In addition, in the actual construction process, a total of 47.4m3 particles were pumped into the well, which is equivalent to 2.3 times of the theoretical volume of the annulus between the screen and the borehole wall. Among them, 20m3 continuous pack-off particles entered the annulus, and 27.4m3 continuous pack-off particles entered the natural fractures in the formation. Through the analysis of CPI completed wells in Liuhua oilfield, it is found out that the overfilling quantity is positively correlated to the effect of water shutoff and oil enhancement.

An Innovative Acid Diversion Using In-Situ Foam Generation: Experimental and Successful Field Application

In carbonate reservoirs, effective acid stimulation is essential to overcome reservoir damage and mainline high oil production. Recently, most of oil wells are being drilled horizontally to maximize production. Acid stimulation of horizontal wells with long intervals require very effective acid diversion system. If the diversion system is not efficient enough, most of the acid will be leaking-off near the casing shoe, in openhole well, which will result in a fast water breakthrough and diminish production. This study describes a breakthrough treatment for acidizing long horizontal wells in carbonate formations. The novel technology is based on in-situ foam generation to divert the acid. Gas diversion, as a foam, is a perfect diversion mechanism as gas creates pressure resistance which forces the acid stages to be diverted to new ones?. The diversion will not require the acid to be spent, compared to viscoelastic diverting system. Moreover, no gel is left behind post treatment, which will eliminate any damage potential. The system is not impacted with the presence of corrosion products, where diverting system will not function without effective pickling and tubular cleanup. Lab results showed that the new in-situ foam generation system was very effective on both dolomite and calcite cores. The system creates high back pressure when foam is generated, which significantly diverts the acid stages to stimulate other intervals. Moreover, the new system minimizes acid leak-off and penetration. Open completing the job, the foam collapse leaving no left behind any damaging material. Field application of the in-situ foam generating system showed high success rate and outperformed other diversion mechanisms. The well gain was up to 18 folds of the original well injectivity.

Carbonate Karstified Oil Fields Geological Prediction and Dynamic Simulation Through Equivalent Relative Permeability Curves

Karst systems heterogeneity may become a nightmare for reservoir modelers in predicting presence, spatial distribution, impact on formation petrophysical characteristics, and particularly in dynamic behaviour prediction. Moreover, the very high resolution required to describe in detail the phenomena does not reconcile with the geo-cellular model resolution typically used for reservoir simulation. The scope of the work is to present an effective approach to predict karst presence and model it dynamically. Karst presence recognition started from the analysis of anomalous well behaviour and potential sources of precursors (logs, drilling evidence, etc.) to derive concepts for karst reservoir model. This first demanding step implies then characterizing each cell classified as karstified in terms of petrophysical parameters. In a two-phase flow, karst brings to fast travelling of water which leaves the matrix almost unswept. This feature was characterized through dedicated fine simulations, leading to an upscaling of relative permeability curves for a single porosity formulation. The workflow was applied to a carbonate giant field with a long production history under waterflood development. Firstly, a machine learning algorithm was trained to recognize karst features based on log response, seismic attributes, and well dynamic evidence, then a karst probability volume was generated and utilized to predict the karst presence in the field. Karst characterization just in terms of porosity and permeability is sufficient to model the reservoir when still in single phase, however it fails to reproduce observed water production. Karst provides a high permeability path for water transport: classical history match approaches, such as the introduction of permeability multipliers, proved to be ineffective in reproducing the water breakthrough timing and growth rate. In fact, the reservoir consists of two systems, matrix, and karst: however, the karst is less known and laboratory analysis shows relative permeability only for the matrix medium. The introduction of equivalent or pseudo-relative permeability curves, accounting for both the media, was crucial for correct modelling of the reservoir underlying dynamics, allowing a proper reproduction of water breakthrough timing and water cut (WCT) trends. The implementation of a dedicated pseudo relative permeability curve dedicated to karstified cells allowed to replicate early water arrival, thus bringing to a correct prediction of oil and water rates, also highlighting the presence of bypassed oil associated with water circuiting, particularly in presence of highly karstified cells.

Modeling a Novel Approach to Delay the Water Breakthrough in Gas Cap Wells Using Smart Completions: Case Study Onshore Abu Dhabi Field

This paper presents modeling a novel approach to determine the impact of implementing smart completions on water injectors located near the periphery of the gas cap and on gas producing wells situated in the gas cap of a giant Middle East onshore field. The objective of the study is to thoroughly investigate different smart completion designs which can effectively delay water breakthrough on the gas cap wells. The study investigates the impact of adding smart well completion designs like ICD and AICD valves in delaying water breakthrough. The first phase involves adding smart completions to only water injectors. Sensitivity runs on several downhole completion design scenarios are conducted using a commercial near wellbore simulator and the optimal downhole completion design is implemented on a dynamic model and its impact is examined using a reservoir simulator. In the second phase, this approach is applied only for gas producers, and in the third phase the smart completions are simultaneously applied to both water injectors and gas producers. The detailed study has revealed that the uncertainties and time involved in selecting optimal ICD design and placements could be reduced considerably by using an optimized workflow. The workflow uses a carefully designed process of using the outcomes from near wellbore simulators and incorporating the results in the actual full field dynamic models to assess the field level impacts. When compared to the bare foot design, ICD and AICD valves showed better performance in delaying water breakthrough from the gas wells. This paper provides a detailed study on the impact of different smart completions on delaying water breakthrough in gas production wells. The study also investigates how a uniform injection or production profile can be produced using different smart completions. Uniform injection and production profiles limit water fingering in the reservoir, and thereby delay water breakthrough caused by the flow of water through high permeability channels.

Maximizing Recovery from a Depleted Oil Rim Carbonate Reservoir Through an Integrated FDP Approach: Case Study Onshore Field Abu Dhabi, UAE

This paper examines risk and rewards of co-development of giant reservoir has gas cap concurrently produce with oil rim. The study focus mainly on the subsurface aspects of developing the oil rim with gas cap and impact recoveries on both the oil rim and gas cap. The primary objective of the project was to propose options to develop oil rims and gas cap reservoir aiming to maximize the recovery while ensuring that the gas and condensate production to the network are not jeopardized and the existing facility constraints are accounted. Below are the specific project objectives for each of the reservoirs: To evaluate the heterogeneities of the reservoir using available surveillance information data.To evaluate the reservoir physics and define the depleted oil rims current Gas oil contact and Water Oil Contact using the available surveillance information and plan mitigate reservoir management plan.To propose strategies in co-development plan with increase in oil rim recovery without impact on gas cap recovery.To propose the optimum Artificial methods to extended wells life by minimize the drawn down and reduce bottom head pressure.To propose methods to reduce the well head pressure to reduce back pressure on the wells. The methodology adopted in this study is based on the existing full field compositional reservoir simulation model for proposing different strategical co-development scenario: Auto gas lift Pilot implementation phase.Reactivate using Auto gas lift all the in-active wells.Propose the optimum wells drilling and completion design, like MRC, ERD and using ICV to control water and gas breakthrough.Proposing different field oil production plateauPropose different water injection scheme The study preliminary findings that extended reach drilling (ERD) wells were proposed, The ability to control gas and water breakthrough along the production section will be handled very well by deploying the advanced flow control valves, reactivation of existing Oil rim wells with Artificial lift increases Oil Rim recovery factor, and optimize offtake of gas cap and oil rim is crucial for increase the recovery factories of oil Rim and gas cap.

Ensemble Data Analytics Approaches for Fast Parametrization Screening and Validation

Ensemble approaches are increasingly used for history matching also with large scale models. However, the iterative nature and the high computational resources required, demands careful and consistent parameterization of the initial ensemble of models, to avoid repeated and time-consuming attempts before an acceptable match is achieved. The objective of this work is to introduce ensemble-based data analytic techniques to validate the starting ensemble and early identify potential parameterization problems, with significant time saving. These techniques are based on the same definition of the mismatch between the initial ensemble simulation results and the historical data used by ensemble algorithms. In fact, a notion of distance among ensemble realizations can be introduced using the mismatch, opening the possibility to use statistical analytic techniques like Multi-Dimensional Scaling and Generalized Sensitivity. In this way a clear and immediate view of ensemble behavior can be quickly explored. Combining these views with advanced correlation analysis, a fast assessment of ensemble consistency with observed data and physical understanding of the reservoir is then possible. The application of the proposed methodology to real cases of ensemble history matching studies, shows that the approach is very effective in identifying if a specific initial ensemble has an adequate parameterization to start a successful computational loop of data assimilation. Insufficient variability, due to a poor capturing of the reservoir performance, can be investigated both at field and well scales by data analytics computations. The information contained in ensemble mismatches of relevant quantities like water-breakthrough and Gas-Oil-ratio is then evaluated in a systematic way. The analysis often reveals where and which uncertainties have not enough variability to explain historical data. It also allows to detect what is the role of apparently inconsistent parameters. In principle it is possible to activate the heavy iterative computation also with an initial ensemble where the analytics tools show potential difficulties and problems. However, experiences with large scale models point out that the possibility to obtain a good match in these situations is very low, leading to a time-consuming revision of the entire process. On the contrary, if the ensemble is validated, the iterative large-scale computations achieve a good calibration with a consistency that enables predictive ability. As a new interesting feature of the proposed methodology, ensemble advanced data analytics techniques are able to give clues and suggestions regarding which parameters could be source of potential history matching problems in advance. In this way it is possible anticipate directly on initial ensemble the uncertainties revision for example modifying ranges, introducing new parameters and better tuning other ensemble factors, like localization and observations tolerances that controls the ultimate match quality.

Advanced Research and Development in Unconventional Use of Tracer Technology for EOR and IOR: What lies beyond?

Over the last few decades, tracers have provided crucial insights on fluid flow behavior assessing reservoir connectivity. For years, they had been viewed as mostly passive molecules that go with the flow of the injected fluid and uncover pathways between injectors and producers. The proposed paper sheds light on some interesting newer frontiers of tracer applications with unconventional uses to gain further flow insight from an oil and gas reservoir. Although primarily developed for interwell applications, newer and more sophisticated genres of tracers have found their way to assist with well fluid flow behavior. Inflow tracer applications, used for phase flow diagnostics, have been around for a few decades now. However, with several parameters like physical space restrictions, temperature, solid support selection, multi-phase flow, initial surge and target concentrations at play, it was soon realised that an extended lifetime was needed to provide techno-economic benefits during reservoir monitoring. Microencapsulation of tracer molecules is one of the newer developed techniques that has shown significant extension to tracer life in controlled release tracer applications as well as improved dispersibility within fracking fluid. Newer synthesis mechanisms like microencapsulation have been developed to linearize inflow tracer release profiles that has led to a substantial increase in tracer lifetime. As the research and development progressed, newer tracers such as frac bead tracers were developed allowing long term fluid flowback monitoring in fracture stimulated wells. In parallel, it is still an active field of investigation as to how tracers can be integrated with common downhole completion and topside equipment of a well to accurately detect early water breakthrough. The paper discusses the advances in these target areas where chemistry is constantly being upgraded to suit end user needs. Novel applications and ‘out-of-the-box’ uses have been developed in the last couple of years where inflow tracers have found a modified use within the gas lift system in a well and integrated with the top-side flow arm of the well, eradicating the need for individual sampling of wells and detection of water breakthrough at an early onset, thus aiding timely decision making and improved recovery from the well. Real time analysis of tracers have attracted attention for quite some time now. The paper also discusses the latest development in this area and the challenges associated with real field applications. While advancements in versatility of the tracer molecules have been published prior in literature, to the best of the authors’ knowledge, no work has been published to date that discusses the latest advances in unconventional uses of the tracer molecules aiding EOR and IOR processes.

Identification and Characterization of High Permeability Zones Using Conventional Logging and Production Logging Data: A Case Study of Kela 2 Gas Field

High permeability zones in the water-drive gas reservoir tend to act as dominant channels for formation water to invade into gas reservoir from the aquifer. The presence of high permeability zones results in uneven water flow front in reservoir and early water breakthrough in gas well, which seriously affects the gas field development. In this paper, conventional logging and production logging data are used to identify and characterize high permeability zones, so as to guide the optimization of development plan of Kela 2 gas field. A method to determine the lower limit of high permeability zones by using cumulative frequency curve of permeability distribution is proposed, and high permeability zones of 21 wells are identified. These high permeability zones account for 10–15% of the effective reservoir thickness in single wells, and they are mainly distributed in the middle of the Bashijiqike (K1bs) Formation (i.e., K1bs12, K1bs21 and K1bs22). The analysis of production logging data shows that the effective gas producing intervals only account for 29.2% of the total number of test intervals, most of which are related to high permeability zones. Further study shows that the high gas flow from the high permeability zones dominates the wellbore production profile, and the gas in low permeability zones flows vertically to the high permeability zones and horizontally to wellbore through these zones. Through the analysis of production profiles over the years and computer modelling, it is confirmed that water channelling occurred in some gas wells at the depth where the high permeability zones are located, which leads to a significant decline in production of these wells. Based on the study of distribution and behaviour characteristics of the high permeability zones, two suggestions on controlling inhomogeneous water invasion are put forward to realize the sustainable and stable production of the gas field.

Seawater Breakthrough Monitoring and Reservoir-Model Improvement Using Natural Boron

Natural geochemical data, which refer to the natural ion concentration in produced water, contain important reservoir information, but is seldomly exploited. Some ions were used as conservative tracers to obtain better knowledge of reservoir. However, using only conservative ions can limit the application of geochemical data as most ions are nonconservative and can either interact with formation rock or react with other ions. Besides, mistakenly using nonconservative ion as being conservative may cause unexpected results. In order to further explore the nonconservative natural geochemical information, the interaction between ion and rock matrix is integrated into the reservoir simulator to describe the nonconservative ion transport in porous media. Boron, which is a promising nonconservative ion, is used to demonstrate the application of nonconservative ion. Based on the new model, the boron concentration data together with water production rate and oil production rate are assimilated through ensemble smoother multiple data assimilation (ES-MDA) algorithm to improve the reservoir model. Results indicate that including nonconservative ion data in the history matching process not only yield additional improvement in permeability field, but also can predict the distribution of clay content, which can promote the accuracy of using boron data to determine injection water breakthrough percentage. However, mistakenly regarding nonconservative ion being conservative in the history matching workflow can deteriorate the accuracy of reservoir model.