bluuebunny/crossref_metadata_2025 huggingface dataset:
Streamline Information Guided by Fuzzy Logic to Optimize Field Injection/Production Strategies
Authors: Y. BuKhamseen Nader , A. Al-Najem Abdullah , Saffar Ali , M. Al-Ghareeb Zeid
Published: July 2016

This paper presents an adaptive approach to optimize field injection strategies using streamline-based well allocations coupled with fuzzy logic. The strength of our approach comes from the fact that streamlines are generated by running full-physics in-house reservoir simulator. Streamlines provide great insights about well pattern connectivity and well allocation factors allowing the injection efficiency (IE) for each pattern to be determined. This enables us to assess and improve the performance of injectors highlighting patterns with low IEs, high voidage replacement ratio (VRR), and high water production to name a few.

Once streamline-based IEs are evaluated, a fuzzy logic system is developed and run to rank the injectors according to their injection performance. Three parameters: IE, water cut, and amount of injected water lost to the aquifer constitute the input to the fuzzy logic system. The fuzzy system categorizes the pattern IEs into four classes: poor, acceptable, good, and excellent. Similarly, it classifies the pattern water cut and the loss of injection into three categories: low, medium, and high. The fuzzy system then outputs an injection-ranking index (IRI) for each injection pattern to recommend a new injection strategy. The new injection rates are then fed into our in-house simulator and results are evaluated to quantify improvements in reservoir sweep efficiency.

This approach has been tested on large-scale simulation models with hundreds of wells and tens of millions of grid blocks. Results show noticeable improvements in injection efficiency for most wells resulting in reducing injection requirements, ensuring better sweep and pressure support without compromising oil production.
Multifidelity Modeling and Analysis of Matrix Acidizing Under Radial Flow Conditions
Authors: Ghommem Mehdi , Brady Dominic
Published: July 2016

Simulating the complex physics and dynamics associated with carbonate acidizing and wormholing phenomenon has been attempted with various types of modeling techniques. In this paper, we follow two modeling approaches with different fidelity levels to simulate carbonate acidizing under radial flow conditions, and describe the wormholing process. The first approach is based on a two-scale continuum technique extended to a three-dimensional cylindrical grid. This model requires discretizing and numerically solving a set of coupled partial differential equations governing the reactive transport of acid at darcy scale and the pore scale dynamics through the structure-property relations. The model shows good capability to reproduce qualitatively the change in the wormhole morphology when varying the acid flow rate. The model is also used to discern the impact of the rock heterogeneity on the wormhole initiation and propagation. While this high-fidelity approach is powerful in terms of capturing the main physical features of the wormholing dynamics at the core scale, the extensive computational resources and time associated with the use of this model could limit the capability of assessing different configurations and operating conditions for design and optimization purposes and upscaling to the field level. This shortcoming presents the need for the development of simplified models that embody relevant physical aspects and provide fast and reliable assessment of the acidizing performance. As such, we consider a second approach with reduced complexity based on combining two quantitative models of linear and radial acid flows in carbonate rocks to track the wormhole penetration and predict the pressure drop resulting from the acidizing of radial cores. A comparative study with experimental results shows that the model predicts well the pressure response and pore volume to breakthrough.
The Impact of the Geochemical Coupling on the Fate of Fracturing Fluid, Reservoir Characteristics and Early Well Performance in Shale Reservoirs.
Authors: Mehana Mohamed , Fahes Mashhad
Published: July 2016

The fate of the fracturing fluid in shale reservoirs is still a controversial issue. Despite the low recovery observed in field reports, neither the fate nor the impact of these trapped fluids is well-understood. The combination of the large surface area, mild reactive nature of shale and the massive trapped volume of fracturing fluids raises a question on the impact that geochemical interactions have on load recovery, well performance and reservoir characteristics, which is the focus of this study.

A fit-for-purpose model is built where a hydraulic fracture stage is modelled using LG-LR-DK model. The initial conditions are simulated by injecting the fracturing fluid, then shutting-in the well to allow the fluids to be soaked into the formation. Different relative permeability sets are used for high and low salinity water since the fluid's mobility is affected by its salinity. Actual connate water composition from Haynesville shale is used to study the impact of connate composition on geochemical coupling. The formation mineralogy and fracturing fluid composition impact on gas and load recovery is investigated.

The introduction of the oxygenated, low salinity, fracturing fluid to a reducing environment would definitely catalyze both precipitation and dissolution reactions depending on the formation mineralogy. The dissolution and precipitation rates show a positive correlation with the carbonate content of the rock. Interestingly, the incorporation of the dependence of relative permeability on ion exchange and fluid salinity might reveal the fate of the fracturing fluid. Overestimation of both gas and load recovery is observed when geochemical coupling is neglected. In addition, sea water shows an enhanced performance suggesting a good alternative fracturing fluid. Surprisingly, better performance is observed for less saline connate water cases. The carbonates reactions outweigh the clays reactions in most cases. Also, treating carbonates as only calcite results in more reactions compared to the dolomite case. Sensitivity analysis suggests that the concentration of SO4, K and Na ions in the fracturing fluid, and illite and calcite mineral content of the rock, along with the reservoir temperature are the main key factors affecting well performance. It is worth noting that the salinity contrast between the injected fluid and the formation brine shows a negative correlation with well performance.

In conclusion, the incorporation of the geochemical coupling in simulating fracturing fluid dynamics, and their impact on the load recovery and well performance, is essential. Therefore, careful selection of a fracturing fluid suitable for formation mineralogy will enhance well performance.
Development Strategy Optimization of Gas Injection Huff and Puff for Fractured-Caved Carbonate Reservoirs
Authors: Li Yong , Wang Daigang , Liu Zhiliang , Ma Xiaoping
Published: July 2016

Naturally fractured-caved Ordovician carbonate reservoirs in China have some distinctive characteristics: deep buried depth, developed multi-scale fractures, vugs and caves, no movable oil in pores, poor reservoir connectivity, isolated reservoirs with small developed volume and high production decline rate. How to effectively develop this kind of reservoirs is a major challenge. This paper presents the detailed development strategies of gas injection huff and puff for different representative fracture-cave type patterns after primary depletion and waterflooding.

Based on the geological study, representative reservoir patterns of fractured-caved carbonate reservoirs can be determined. And combined seismic interpretation, geological study and dynamic characterization, different development patterns can be identified and characterized. After that, simulation models of different development patterns with different fracture-cave architectures are built, and development strategy for representative isolated development patterns with gas injection huff-and-puff are detailed studied and optimized.

The technology is applied to K fractured-caved Ordovician carbonate reservoir of Tarim Basin in China. The mid-depth of K reservoir is 6500m with well annual production decline rate higher than 25%, and current oil recovery is only around 7% of OOIP. Through the geological and dynamic characterization, 3 representative reservoir type patterns are identified and characterized. And simulation models of the 3 patterns with different fracture-cave architectures for the three patterns are built to investigate the optimized development strategies of gas injection huff-and-puff. The optimized parameters include gas injection rate, cyclic soak time, cyclic injection volume, liquid off-take rate, etc., which are applied to the gas injection pilots in K reservoir, and the results show gas injection huff-and-puff can highly improve oil recovery.

This paper offers a case study on optimizing the development strategy of different reservoir patterns for fractured-caved carbonate reservoirs. It also provides a methodology and an improved oil recovery reference case for engineers and geologists to develop other similar reservoirs.
Enhancing Oil Recovery - Advanced Simulations for More Accurate Frac-Stages Placement
Authors: Saad Bilal , Negara Ardiansyah , Hussain Maaruf , Elgassier Mokhtar , Sun Shuyu , Abdullah King
Published: July 2016

Hydraulic fracture stimulation designs are typically made of multiple stages placed along the lateral section of the well using various well completion technologies. Understanding how multiple hydraulic fractures propagate and interact with each other is essential for an effective stimulation design. The number and placement of stages are important factors for optimizing the performance of the laterals. This in turn depends on accuracy in determining fracture interference. We present advanced simulations for accurate placement of well stages. In this paper, we use a 3-D fully coupled geomechanical-fluid flow simulator which incorporates anisotropic geomechanical properties. Densely complex natural fractures and lamination are built into the model based on available core and log information. Multiple fractures are concurrently imployed to simulate real life scenarios. Fluid pressures are incrementally computed such that stress state changes dynamically with time as it happens in real field situation. Our simulations were run on Cray XC 40 HPC system. The results demonstrate that the stress shadow effects can significantly alter hydraulic fracture propagation behavior, which eventually affects the final fracture geometry. The results show that there are large differences in aperture throughout the stimulation which persists to the end of pumping. Furthermore comparison between cases with and without complex natural fractures (discrete fracture network (DFN)) and lamination was conducted with even and uneven spacing configurations. Fracture interference and spacing analysis conducted based on model with perforation frictions shows that while spacing between fractures is important, the largest impact was observed in the presence of lamination and DFN. The large differences in the way the fracture propagates highly depend on the DFN connectivity. Late-stage connection throughout the model implies later disconnection when the pressure drops. Though the computations are time intensive, we believe this is a valuable tool to use in the planning stages for asset development to increase production potential.
The Use of Local Sand for Hydraulic Fracturing in Saudi Arabian Gas Fields
Authors: Alabbad Emad A. , Tarihoran Anton R. , Saldeev Ruslan , Al-Harbi Moataz M. , Al-Kulaib Hamad F. , Al-Atwi Mohammed A. , Hansen Jon E.
Published: July 2016

Hydraulic fracturing has been an essential part of the gas development program in Saudi Arabia. In particular, proppant fracturing treatments have increasingly grown in number in recent years, which provided an incentive to look for viable alternatives to imported proppants. A new hydraulic fracturing design that utilized local sand as nonstandard proppants was recently applied in gas wells producing from sandstone formations in Saudi Arabia. This paper presents the theory behind the new fracturing design and summarizes the main results and recommendations.

Sand quality-control lab tests were required prior to using Saudi Arabian sand as a propping agent in fracturing gas wells. The sand samples were analyzed for particle sizes, bulk densities, and compressive strengths. Well selection to apply the fracturing stimulation was then made based on a geomechanical criterion for the reservoir rock and the well's production performance. The treatment design utilized a channel-fracturing technique where the solids used comprised of roughly 65% natural sand and 35% ceramic proppants.

The results show successful placement of the fracturing treatment into the formation. Despite sand crushing, the data show reasonable stimulation results and productivity enhancements. A number of important findings were also realized based on the analysis of the production performance, the reservoir transient pressure data, and the recovered solids and liquids.

The discussions shared in this work including analysis of field data yielded important findings and recommendations. Particularly, the concept of applying nonstandard proppants, such as silica sand for hydraulic fracturing treatments is proven feasible. Overall, the new fracturing technique shows considerable potentials for sufficient process optimization and utilization of abundant resources in production operations.
Optimizing Reservoir Performance through Utilization of Autonomous Inflow Control Valve – Lessons Learnt from the World’s First Installation
Authors: Nugraha Ikhsan , AlBassam Terki K , Gallelli Alessandro , Mathiesen Vidar
Published: July 2016

One of the major challenges in mature oil fields is to improve recovery from existing fields by developing and implementing new technologies that make operations efficient and cost effective. For a reservoir with a water or gas drive mechanism, the mobility ratio between oil and water or gas becomes more critical due to the lower viscosity of water or gas. Observably, breakthroughs can occur within relatively short periods of production time. Once breakthrough occurs, gas or water production can rapidly dominate production prompting well intervention or the shutting-in of production, leaving unrecovered oil behind.

Inflow control device (ICD) and autonomous inflow control device (AICD) have shown oil production and recovery can be increased significantly with better inflow control/pressure regulation along the lateral, which to some degree has resulted in breakthrough delays. However, neither ICD nor AICD are able to shut off unwanted gas and water production completely. The autonomous inflow control valve (ICV) offers the functionality of conventional ICD and can actively shut off unwanted fluid completely.

The paper describes the development of Autonomous ICV, experimental test results, and preparations prior to the completion installation. The main challenges and conclusion from the field tests are presented and discussed based on the initial flowback data where the functionality of Autonomous ICV was verified, i.e., by shut-off of low viscosity fluid, such as water, and opening for oil with higher viscosity.
First Time Live Descaling Operation in Saudi using Coiled Tubing Fiber Optic Real-Time Telemetry Rugged Tool, Foamed Fluid and Pressure Fluid Management System
Authors: Espinosa G Mauricio A. , Leal Jairo A. , Driweesh Saad M. , Buali Mustafa F. , Khnaifir Waleed K. , Jasim Ali J. , Noaman Yousef M. , Sa Rodrigo , Arifin Mohammad
Published: July 2016

Saudi Aramco has long faced significant challenges to remove scales from the wells due to the high H2S contents and the sub hydrostatics reservoir pressure. Conventional techniques often fell short of expectations in the past, there had been cases of uncontrolled H2S releases at surface, which caused major HSE issues to the personnel; also coiled tubing (CT) got stuck due to sudden loss of circulation stemming from the inability to control the bottom-hole pressure and the instability of the fluid system during the scale removal treatment. As a result of those repeated issues, scale removal treatments were suspended for some time waiting for a safe technique to be devised. As a first step, the service company proposed to use a non-damaging chemical plug technique to temporarily plug the open perforations during the scale removal treatment, in an effort to avoid H2S release and to maintain circulation. The first results of this technique showed a marked improvement, which led the operator to resume the descaling operations, but in some operations the isolation process was extended several days and a large amount of fluid were injected into the formation, leading to induced damage, requiring high volume acid stimulation treatment and longtime flow back operation, to get the well back in production.

To further optimize descaling operations via CT in Saudi Aramco, a novel scale removal technique was introduced that leverages the real-time downhole monitoring capabilities of CT equipped with fiber optics, to obtain a constant feedback on downhole conditions and allow swift adjustments to ensure safe operations. It also uses a redesigned foam system and implements a new pressure and fluid management system (PFMS), to eliminate the use of the temporary plug across the formation.

With CT fiber-optic real-time telemetry, engineers can control the bottom-hole pressure throughout the intervention, to maintain the well slightly over-balanced and to prevent H2S from being released during fluid circulation. This system counts with a bottom-hole assembly (BHA) that gathers a full array of real-time sensors (pressure, temperature, casing collar locator, gamma ray, load measurements), and is compatible with downhole tools that require high flow rate to operate — in this case, a 2-7/8-in. turbine with a nominal flow rate of 2.8 bpm). This BHA can withstand a high level of shocks, vibrations and bottom-hole temperatures in excess of 300°F. As for the foam system, it ensures stable solid transport from downhole to surface conditions minimizing leak off into the formation, while the pressure flow management system (PFMS) is used to accurately control wellhead pressures, thanks to an array of auto chokes to control solid returns, and to remove entrained gasses (including H2S) from the returning fluid.
Application of a Deconvolution Technique in PTA for Enhanced Reservoir Characterization
Authors: Ahmad S. B. , BinAkresh S. A. , Anisur Rahman N. M.
Published: July 2016

Current trends toward permanent downhole instrumentation allow the acquisition of large sets of well test data, ranging over much longer periods of time than was possible in the past. Such data sets can contain information about the reservoir at a substantially larger radius of investigation than the one accessible to conventional well test analysis methods, which is limited to the interpretation of single flow periods at constant rates. By contrast, deconvolution methods do not suffer from such a constraint as these are designed to perform analyses at variable flow rates. Deconvolution is a technique, which can be used to convert measured transient pressures from variable rate changes into the transient pressure response as a result of an equivalent constant flowing rate.

In this study, we will discuss a field case from an intelligent field, where deconvolution techniques have been successfully implemented in pressure transient analyses. The subject intelligent field has generated large data sets that span months to years. The case study showed that the additional reservoir characterization has been achieved through revealing responses in deeper regions of investigation, which would have been impossible without applying a deconvolution technique. The technique has proven the communication between reservoir layers and identifies the presence of aquifer. Methods independent of the deconvolution methods have suggested aquifer volumes that are very close to the one determined from the transient model. The upper completed layer is isolated from high porosity, high permeability zone below it, which has not been obvious from the conventional analysis of data within the normal test duration. Deconvolution method used managed to address the issue and allow the utilization of the complete data set for enhanced reservoir characterization.
Surfactant Derived from Natural Renewable Product for SP Flooding in High Temperature, Low Salinity Reservoir
Authors: Hongyan Cai , Qiang Wang , Jian Fan , Wanlu Liu , Wenli Luo , Ming Gao , Zhengbo Wang
Published: July 2016

Surfactant/Polymer binary flooding technique has become one of the most important research fields in CEOR due to the prevention of side-effects of alkali. Nevertheless, the lack of efficient surfactant greatly restricts the in-lab evaluation and field application of this promising technique. Without the help of alkali, surfactants with higher interfacial activity are needed in SP flooding compared with their counterparts in ASP. It is even harder to find an ideal surfactant for SP flooding in high temperature, low salinity reservoir because the requirements on stability and interfacial tension decreasing capability of surfactant become more challenging.

A betaine surfactant derived from oleic acid, which is a product hydrolyzed from renewable conventional vegetable oil, was prepared through four step reactions. Related SP formulation utilizing this betaine was developed for a high temperature, low salinity sandstone reservoir with formation temperature at 85°C and brine salinity at 1270 mg/L. Comprehensive evaluations, including interfacial activity with crude oil, phase behavior, static adsorption, and long term thermal stability were preformed for this surfactant.

The results showed for the solutions of prepared oleic acid derived betaine surfactant with concentrations ranging from 0.03%wt to 0.20%wt, ultralow interfacial tensions were reached with crude oil, demonstrating higher interfacial activity compared with conventional surfactants used in high temperature, high salinity reservoirs. Phase behavior test showed lower phase microemulsion was formed. Static adsorption and long term thermal stability tests also showed qualified results. Nature core flooding tests demonstrated for the selected SP formulation, the enhanced oil recovery of chemical flooding reached 15.2%.

The Developed betaine surfactant showed good performance for SP flooding in high temperature, low salinity reservoir. It bridges natural renewable product and enhanced oil recovery of fossil fuel, which is in accordance with sustainable development concept and displays a promising direction for the R&D of green and efficient alkali-free surfactant.
Transforming Oil Tracer Studies
Authors: Ellis Erika S , Kosynkin Dmitry , Askar Mohammad N
Published: July 2016

Chemical and radioactive tracers have been used for decades in the oil industry to track injected fluids to map inter-well permeable paths (as passive tracers) and as active tracers to identify reservoirs that are specifically suited for EOR operations by detecting residual oil saturation. The down side of using these types of tracers is the high cost of materials, time consuming collection, costly lab analysis and high safety hazards of the materials themselves. Saudi Aramco's Reservoir Engineering Team has made significant progress towards using nanoparticles as active and passive reservoir tracers that are inexpensive, easy to produce and pose very low safety hazards personally or environmentally. Additionally, Aramco has been developing a portable stand-alone system that can detect these advanced nanoparticle tracers in real-time, directly from the well head with no need for sample collection or lab analysis and can run without operator intervention for at least three months. This paper presents the prototype stand-alone sensing system for advanced nanoparticle tracers which has the potential to transform the efficiency of current nanoparticle oil tracing practices by nearly 99% by reducing collection and processing time from around 10 hours to <5 minutes in real time. Recent results show the system's ability to separate, purify and detect fluorescent nanotracers from produced water to 0.1ppm levels in a portable inline process.
Effects of Multiple Transport Mechanisms on Shale Gas Production Behavior
Authors: Negara Ardiansyah , Sun Shuyu
Published: July 2016

Gas transport in extremely low-permeability shale formations is a multi-mechanisms-coupling process that includes gas adsorption-desorption, Knudsen diffusion, and slip flow. Incorporating these mechanisms into a unified mathematical model is crucial to obtain a more accurate shale gas production behavior. The objective of this paper is to investigate the effect of each mechanism on shale gas production behavior. We establish shale gas dual-porosity dual-permeability model that incorporates gas adsorption-desorption, Knudsen diffusion, and slip flow as well as the thermodynamics calculations. Peng-Robinson equation of state (PR-EOS) was used to calculate the gas density and compressibility factor by solving the cubic equation. In our model, gas adsorption-desorption obeys the Langmuir's isotherm as a function of reservoir pressure. Furthermore, gas viscosity changes with Knudsen number during the pressure depletion; and pore radius will increase when the adsorption gas desorbs from the pore wall. In the numerical method implementation, we combine the finite volume method with the experimenting pressure field approach to obtain the pressure distribution in the matrix and fracture systems. In this study, we investigate the effects of adsorption, Knudsen diffusion, and gas-slippage (Klinkenberg effect) on shale production behavior. We switch each mechanism on and off in the model to observe its effect on the production performance. It is observed from the results that among these mechanisms, adsorption has a great influence on gas production. Ignoring adsorbed gas would lead to a lower cumulative production. Meanwhile, the effects of Knudsen diffusion and slip flow are not as significant as adsorption. In particular for the example presented in this paper, neglecting adsorption will decrease the production nearly 80% compared to 15%-18% when Knudsen diffusion and slip flow are ignored. Knudsen diffusion and slip flow have less impact on the production because both mechanisms occurs in the matrix and contribute only to the apparent permeability, while the production is mainly determined by the fracture permeability, which is critical in determining fluid flow from the fracture system to the wellbore.
A Novel Approach to Compare Pressure Regimes for Compartment Identification in Low Mobility Environment
Authors: Sharma Shivam , Batshas Siddhanta , Joshi Sameer , Tewari Shagun , Shukla Sourabh , Agarwal Ankit
Published: July 2016

Formation pressures recorded by Wireline Formation Testers are widely used for identification of compartments based on the pressure regimes. If two virgin zones are at the same pressure regime, it is not a sufficient condition to conclude that they will be in communication during the production life of the field. This is because pressure equilibrium has been attained over geological timescale and the zones may or may not be in communication in the production timespan. But on the other hand, if two virgin zones are found to be at different pressure regime, it can be safely concluded that the zones will not be in communication and thus, belong to separate compartments. While such analysis can be easily carried out for high mobility/ permeability zones, interpretation in case of low mobility zones is often challenging. In low mobility environment the pressures are not very reliable due to incomplete stabilization of buildup and supercharging effects. It is a big challenge to find whether 2 zones have same pressure regimes or not in low mobility scenario. This limitation hinders effective usage of pressure data when formation mobility is low.

In the current study, a novel approach has been adopted to analyse the pressures measured by formation testers across multiple zones. For diagnosis of the pressure regimes, a cross plot of excess pressure (Alton Brown et al. AAPG, 2003) versus mobility has been used. This cross plot resembles an exponential decline trend for all the points lying in the same pressure regime. The empirical relationship is supported by analytical models available in the prior literature. Under virgin conditions, the zone whose excess pressure points do not lie on the postulated curve is in all likelihood at a different pressure regime.

The workflow has been tested on multiple data sets from various exploratory wells in India. Using this technique, it became possible to identify separate compartments in low mobility environment. For validation, this technique was applied on the data sets where one or two high mobility points were also available. The compartment identification from excess pressure mobility cross plot corroborated with the interpretation based on the high mobility pressure points.
A Systematic Technique of Production Forecast for Fractured Vuggy Carbonate Gas Condensate Reservoirs
Authors: Li Yong , Zhang Jing , Liu Zhiliang , Li Baozhu , Deng Xingliang
Published: July 2016

Naturally fractured-vuggy carbonate gas condensate reservoirs in China have some distinctive characteristics: deep buried depth, multi-scale fractures, vugs and caves developed, poor reservoir connectivity and high production decline rate. It is hard to build effective geological models and run reservoir simulation for production forecasting. So how to properly forecast the performance of this kind of reservoirs is a major challenge. This paper presents a systematic technique of production forecast to solve this problem.

The systematic technique mainly involves analytical and numerical production analysis (PA), analytical and numerical pressure transient analysis (PTA) and material balance analysis in combination with the geological analysis results. Firstly, using the analytical PA and PTA can quickly and correctly evaluate reservoir properties. Take Tazhong No.1 carbonate gas condensate reservoir in China for example to elaborate the details of this method. The results show that the systematic method can not only properly calculate the reservoir properties, but also can quickly and properly forecast reservoir performance of fractured vuggy carbonate gas condensate reservoirs. And the calibrated dynamic numerical model can both match well production history data and well pressure data. Examples are presented to show how these material balance analysis, analytical and numerical PA and PTA methods fully integrated and constrained with each other, and how the reliable results can be generated finally. Because of the poor connectivity characteristic of Tazhong No. 1 field, dynamic models for each fractured-caved unit should be built and applied for performance prediction.
Optimizing Water Flood Performance to Improve Injector Efficiency in Fractured low-Permeability Reservoirs Using Streamline Simulation
Authors: Li Junchao , Lei Zhengdong , Li Shujun , Zhang Ran , Wang Fang , Yu Tao , Su Yantao , Tang Zichun
Published: July 2016

Objectives/Scope

Waterflooding has been the main development method for maintaining the formation energy in low-permeability reservoirs. Often these reservoirs are characterized by poor sweep and high water cut of oil wells due to natural fractures. Streamline technology is an ideal tool for optimization of waterflooding operations. One of the main advantages of streamline simulation is to display paths of fluid flow and to calculate rate allocation factors. However, describing fluid transport in fractured low-permeability reservoirs entails additional challenge because of the complicated physics arising from matrix-fracture interactions.

Methods, Procedures, Process

In this paper we demonstrate a straightforward workflow for optimizing injection rate based on a comprehensive analysis of injector efficiency (IE). First, the streamline model including improved transfer function and non-Darcy flow of matrix is generalized to describe fluid transport. In particular, the streamline time of flight concept is utilized to develop a general dual porosity dual permeability system of equations for water injection in naturally fractured reservoirs. The streamlines can be derived from the flux field of this model that represent a snapshot of the flow pattern within the reservoir, well drainage region information and fluid allocation changes with the flood progression. Second, using an analytical calculation to compute weighting factors for injection/production rate targets from a derived ranking of the wells (IE). Finally, reallocation of injected fluid volumes from low-efficiency to high-efficiency injectors improves volumetric displacement and sweep efficiency in the less swept areas of the reservoir. The application of this workflow is demonstrated with a real-field example of an fractured low-permeability sandstone reservoir in Chang Qing oilfield in China where the pattern balancing has led to incremental production over the 5 years forecast in which the IE average of the field is the benchmark while obeying facility constraints.

Results, Observations, Conclusions

The results indicate that water cycling was quantified by streamline simulation and water injection with a decrease of 30-40% on the maximum principal stress direction causes in a reduction in the produced water volumes. A new water injection strategy was implemented, and a decrease in water cut on this challenge sector was achieved in the targeted producers.

Novel/Additive Information

This work provides a comprehensive case study and useful method for better understanding the fractures on waterflooding performance and optimizing production plan of maximizing oil recovery on the fractured low-permeability reservoir.
Evaluation of a New Elemental Spectroscopy Device for Carbonates in Saudi Arabia
Authors: Saldungaray Pablo , Al-Tajar Firas , MacDonald Robin , Musharfi Nedhal
Published: July 2016

Elemental Spectroscopy measurements have become a standard component of the logging program in Exploration, Delineation and special Evaluation wells for Saudi Aramco. Elemental Spectroscopy data has proved critical when evaluating complex lithology formations in both siliciclastic and carbonate rocks to produce an accurate mineralogy analysis, resulting in good understanding of the subsurface lithology in a cost effective way.

A rigorous qualification protocol is applied to novel services when they are introduced to Saudi Aramco. New measurements are compared to existing equivalent services if available and to core data if applicable. For the specific case of the new Elemental Spectroscopy device, the elemental outputs were compared to a previous generation tool and to elemental concentrations from core measurements in a wide variety of formations and lithologies in clastic and carbonate reservoirs. Clastic reservoirs were covered in previous publications; in this work we show the results for carbonate rocks.

Initial comparisons between the previous and new generation tools showed good agreement for most of the elements except for Mg (Magnesium) at low concentrations. Several samples were selected from Jurassic carbonate reservoirs to understand better differences at low Mg concentrations. All samples were taken as 1 foot side trims from a full core slab. The samples were crushed and homogenized to minimize the effects of heterogeneity. The prepared samples were analyzed using X-ray fluorescence (XRF) for elemental concentrations and Dual Range Fourier Transform Infrared Spectroscopy mineralogy (DT-FTIR) for mineralogy. The elemental results from both tools and the core samples were then plotted and compared.

While existing measurements work in many areas, there are specific cases where the new technology can generate improved formation evaluation in carbonate formations or increase efficiency by logging faster.
Fractured Shale Gas Reservoir Development Evaluation Based on Discrete Fracture Model
Authors: Mi Lidong , Zhang Yanqing , Jiang Hanqiao , Wang Zhifa , Li Junjian , Liu Chuanbin , Liang Bin , An Cheng
Published: July 2016

The present paper evaluates the development effectiveness of fractured shale gas reservoirs by fractured horizontal wells based on discrete fracture model. In this model, the flow in matrix meets "non-Darcy law" because of the ultralow permeability when using "Cubic law" to describe the flow in fracture that is high flow conductivity and the simulation is carried out by solving the nonlinear partial differential equations using finite element method. The method of fracture treatment in this model is more suitable to characterize the function of individual fracture than the traditional method. Establishing several conceptual models with different fracture parameters to investigate the exploitation characteristic by multistage fracturing horizontal well. The preliminary simulation results show that: (1) Horizontal well is superior to vertical well when developing the fractured shale gas reservoir. (2) Multistage fracturing horizontal well is an effective method to amplify drainage area and raise well production. (3) Improving the natural fracture properties, such as fracture aperture that connect to hydraulic fracture, is important to improve development effect. (4) Well type, horizontal well length, hydraulic fracture number, spacing, length and natural fracture aperture are the main factors that determining the development effect of fractured shale gas reservoir. Therefore, Horizontal well development, multistage fracturing horizontal well, extending horizontal well length, enhancing the natural fracture aperture that connect to hydraulic fractures, increasing hydraulic fracture number and shorting hydraulic fracture spacing is helpful to improve the development effect of shale gas reservoir.
Cost Effective Chelating Agent EOR Fluid System for Carbonate Reservoirs
Authors: M. Hassan Amjed , S. Al-Hashim Hasan
Published: July 2016

This paper presents a new approach for flooding carbonate reservoirs using chelating agent fluid system prepared using seawater without dilution. Sequential coreflooding tests using limestone core samples following seawater flooding with an increasing concentration of the chelating agent EOR fluids revealed significant incremental oil recovery ranging from 16 to 26%OOIP without any significant increase in the pressure drops. The sequential flooding starts with small concentrations of the chelating agent EOR fluid to alter the wettability of the limestone surface to a more water wet condition through gradual surface rock dissolution.

Zeta potential measurements as a function of chelating agent EOR fluid concentrations showed that increasing the concentration of the chelating agent resulted in altering the limestone surface charges to more negative values. Interfacial tension, IFT, was measured as a function of chelating agent the concentrations and found to decrease as the chelating agent concentration increases.

This new approach minimizes the use of large quantities of chelating agent chemicals and consequently reduces the cost.
Designing and Implementation of the First Steam Flooding Pilot Test in Sudanese Oil Field and Africa
Authors: Elbaloula Husham , Pengxiang Hao , Elammas Talal , Alwad Fahmi , Rdwan Mosab , Musa Tagwa
Published: July 2016

Steam flooding is to heat the oil to higher temperatures in order to decrease its viscosity so that it will be more easily flows through the formation from injector toward the producing wells, as the steam moves out into the reservoir away from the injection well, its temperature drops from heat losses and it begins to condense as hot water in the steam zone, the residual saturation is lowered, and the relative permeability increased. These represent the most important parameters that affect the oil recovery.

The objective of this paper is to select the optimum pilot area and propose the steam flooding injection parameter, the suitable well spacing as well as the required steam flooding facility for FNE oil field.

FNE reservoirs are highly porous (~30%), permeable (1000-2000 mD) and unconsolidated in nature. the fluid properties include viscous crude with 15 to 17.7 API. Corresponding viscosities are in the range of 250 cp and 500 cp at reservoir conditions.

In this paper the model was designed to simulate steam flooding of heavy oil reservoir in FNE oil field in which the reservoir is shallow and thin, six different cases at different well spacing were investigated and compared with the base case, the numerical thermal simulator was used to simulate the data from the present steam flooding experiments.

Steam injection temperature of 270°C, with 5~7 MPa injection pressure, steam injection quality of 0.6, and steam injection rate of 1.6 m3/d/ha/m; were used as Steam Flooding parameters for all simulation cases while the recovery ratio of 1.2 is also considered.

The result showed that converting of Cyclic Steam Stimulation (CSS) to steam flooding after the third cycle could improve the recovery factor of the field up to 43 ~ 50.1%, while CSS only can increase the recovery percent of the suggested well groups by 32.5 - 34.2% of the studied sector model which makes it more attractive method as development scenario for FNE oil field.
Feasibility Study of Utilizing Hydraulic Turbines to Recover Excess Power from Water Injection Systems
Authors: AlAjmi Mohammed D. , Mahsoon Ahmed H. , Al-Hajri Nasser M.
Published: July 2016

This paper will outline the results of a field feasibility study to utilize hydraulic turbine applications for power recovery in water injection systems. The working principle of hydraulic turbine includes recovering excessive and unutilized energy in liquid flow systems. This is achieved through converting unexploited injection system pressure to electrical power generated by rotating turbines.

The powered water injection systems are often restricted to meet injection targets as part of the reservoir injection strategy to support oil production. Pressure losses in powered water injection systems take place at surface chokes that regulate injection target rates. Expected pressure losses in an injection flowline was determined through the analysis of frictional and gravitational pressure losses. The injection pump performance curves were also factored in as part of this rigorous evaluation. The feasibility study has been conducted with flexibility in mind to account for future changes in reservoir injection/production strategies.

Field-A candidates were explored and vetted to ascertain the achievability of applying this innovative power recovery concept on existing injection systems. A systematic candidate selection roadmap was established. The objective of this conceptual roadmap is to provide a means for conducting the primary assessment of candidate injection systems in Field-A. Several suitable injection systems were selected after a prudent evaluation of possible power recovery turbines candidates in Field-A. The expected power saving realized from applying hydraulic turbines was quantified in terms of net present value and return on investment. The economic impact from converting this pressure to power a hydraulic turbine was established, bearing in mind: The initial capital investment.Payback period.The projected inflation rate.The equivalent gas sales required to generate this power.
Seawater Fracturing Fluid Development Challenges: A Comparison Between Seawater-Based and Freshwater-Based Fracturing Fluids Using Two Types of Guar Gum Polymers
Authors: Alohaly Maryam , BinGhanim Ahmed , Rahal Raed , Rahim Sabiq
Published: July 2016

During the past several years (i.e., 2006 to 2014), the US transformed the development of shale oil and gas from slow and steady into a shale gas boom by combining two already existing technologies—multistage hydraulic fracturing and horizontal wells. This helped the US once again be energy-independent regarding natural gas supply (Charlez 2015). Inspired by such success, the Kingdom of Saudi Arabia and the Middle East region are meeting the increasing energy demand by following similar steps (Bartko et al. 2012).

Large stage sizes in hydraulic fracturing and horizontal drilling long laterals require large quantities of freshwater. Despite the fact that the Arabian Peninsula lacks freshwater resources, fresh water is still consumed by the oil and gas industry in the region. Conversely, seawater is plentiful and should substitute for freshwater in unconventional resource operations. However, the high salinity of seawater raises many chemical challenges in developing design criteria for fracturing fluids.

To help mediate this problem, this paper studies the chemistry of developing seawater-based fracturing fluids using two types of polymers as gelling agents and compares results to already existing freshwater-based fracturing fluid data under different conditions. Various seawaters from around the world were compared to Arabian Gulf seawater and its various compositions throughout the year. The local seawater's high total dissolved solids (TDS) measurement is 54 000 mg/L and includes sulfate (>4000 mg/L), calcium (>600 mg/L), and magnesium (>1700 mg/L). These are the major ions that cause delayed hydration, alteration of the crosslinking mechanism, and high scale formation, along with barite (BaSO4).

Moreover, the paper presents a better understanding of fluid behavior by studying the effects of sulfate (>4000 mg/L), calcium (>600 mg/L), and magnesium (>1700 mg/L) individually to observe fluid stability at high temperatures in both polymers.
A Novel Approach to Predict Wellbore Stability - Use of Thermogravimeteric Characterization to Quantify Rock-Fluid Interaction
Authors: Patil Umesh , Yadav Prahlad , Agrawal Gaurav
Published: July 2016

This paper reports the laboratory study to check the influence of water content, amount, distribution, and water types, on shale reactivity. Even though it is known that any change in water content affects shale behavior, quantification had not previously been attempted. A new method using thermogravimetry (TGA) is developed to determine the water content and provided the opportunity to quantify water loss severity due to dehydration. For a complete understanding of shale-fluid interaction, a more detailed characterization methodology was necessary. The most popular method used by the industry, X-Ray diffraction (XRD), has limitations with shale samples. The proposed methodology uses TGA and is presented here. It has several advantages when compared to XRD. The composition of the rock can easily be identified and structural changes of the rock can be observed.