bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dynamic Water Flooding in Carbonates: The Role of Iodide Ions
Authors: Al Hamad Mohammed , AlZoukani Ahmad , Ali Farhan , Badri Mohammed , Abdallah Wael 
Published: June 2017

Abstract
Seawater injection has demonstrated a successful and a well-established procedure for reservoir pressure maintaining and sweeping oil out of the reservoir. However, in most cases seawater by itself showed low incremental oil recovery, many research studies have shown that further dilution of the injected seawater is capable of altering the carbonate formation's wettability from mixed or oil-wet to more water-wet and therefore additional oil recovery. However, dilution requires massive volume of fresh water which is an expensive commodity and therefore it will not be practical in real applications.
The following study provides for the first time a novel concept for boosting oil recovery with use of halides ions in very small concentrations without the need for seawater dilution. Halides ions (iodide ions) are added to the seawater with different concentrations (1000 ppm and 2000 ppm) to formulate what we call the "Dynamic Water". The efficiencies of the different prepared Dynamic Waters (with different iodide ions concentrations) were compared to seawater by performing IFT, contact angle, spontaneous imbibition and coreflooding experiments.
Although all prepared Dynamic Water mixtures have higher salinity than seawater, they had insignificant impact on lowering the IFT, but they significantly alter the rock wettability to stronger water wet, which is an important oil recovery mechanism. The performance of the Dynamic Water on oil recovery was also investigated in this study by means of spontaneous imbibition and coreflooding experiments. Six samples were utilized for these experiments, three dolostones and three limestones. Initially, the three limestone samples were considered for spontaneous imbibition where Dynamic Water proved to be efficient in recovering oil from all the samples. After sample cleaning, the same three limestone samples in addition to the three dolostone samples were used for coreflooding under reservoir conditions of high pressure and high temperature. Good oil recoveries were achieved from almost all the samples by coreflooding, with maximum additional oil recovery of 16.9% from one of the limestone samples.
Influence of Rock Wettability Alteration on Dielectric Dispersion Data
Authors: Al-Ofi Salah , Sauerer Bastian , Dyshlyuk Evgeny , Valori Andrea , Abdallah Wael 
Published: June 2017

Abstract
Rock surface wettability controls the fluid distribution in the pore space of the formation and thus, has an influence on its electrical properties. The variation of dielectric dispersion data with the variation of formation wettability is not well understood at present time.
In this study, we investigated the influence of wettability alteration on dielectric dispersion data by laboratory experiments using different dielectric data interpretation models. We used a reflection open-ended coaxial probe to measure dielectric dispersion of a 1.5-in. core plug in a frequency range of 10 MHz to 1 GHz. The studied rock wettability was varied in a coreflooding apparatus during a drainage experiment. We used low-polarity oil for the initial drainage to preserve the rock in the water-wet state and added different concentrations of surface-active stearic acid to the oilflood during later drainage stages to change the sample wettability. The used dielectric data interpretation models, in addition to standard interpretation answers, solve for geometrical parameters of the fluids and pore space, which allow us to evaluate wettability variation.
Our results showed a decrease in dielectric dispersion at the low-megahertz frequency range as we inject higher acid concentrations into the rock. This decrease in the dispersion also corresponds to an increase of the inverted MN-parameter, which characterizes water phase tortuosity. The results of the inversion, using the textural model, showed a consistent decrease of the depolarization factor of water inclusions as we increase the acid concentration in the injected oil. At the highest acid concentration used (1 wt%), this depolarization factor drops down to 0.36, which is very close to the depolarization factor of spherical inclusions. It follows from our findings that water films, which are characteristic for water-wet rocks, are transformed to more spherical droplets due to the change of wettability to oil-wet state. NMR T2 measurements on the same plug and contact angle measurements on reference samples of same lithology support our conclusions on wettability variation.
This study illustrates how to interpret the rock wettability state from dielectric dispersion data based on geometrical models and how to use the inverted geometrical parameters as a wettability indicator.
A Laboratory Study of In-Depth Gel Treatment To Improve Oil Recovery
Authors: Wang Jinxun , Alshehri Ammar J. , AlSofi Abdulkarim M. , AlBoqmi Abdullah M. 
Published: June 2017

Abstract
The extreme heterogeneity of carbonate in the form of fracture corridors and super-permeability thief zones challenges the efficient sweep of oil in both secondary and tertiary recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any enhanced oil recovery (EOR) chemicals optimally contact the remaining oil with minimal throughput. Gel-based conformance control has been successfully applied on both sandstone and carbonate reservoirs. In-depth conformance control in high temperature reservoirs is still a challenge, due to severe gel syneresis and the associated significant reduction in gelation time.
In this work, a laboratory study was conducted on a polymer/chromium gel system for a high-temperature carbonate reservoir to evaluate the gelant formulation potential for diversion and recovery improvement. We perform four oil displacement experiments on carbonate core samples to demonstrate oil recovery improvement by gel treatment. In these tests, the gel solution was injected into specially prepared heterogeneous carbonate composite core samples, in which different configurations of high permeability channels were created. Gel treatment was conducted after waterflooding and was followed by chase waterflooding while monitoring oil production. Oil recovery improvement by gel treatment was 18% of original oil in core (OOIC) in the composite core with high permeability channels extending midway through the composite while the improvement was 38% OOIC in the composite core with channels extending all the way through the composite. This indicates that the high permeability channels were effectively blocked and bypassed oil was successfully mobilized after gel treatment.
This laboratory study provides more insight into the mechanisms of oil-recovery improvement by gel treatment. Moreover, it clearly demonstrates the oil-recovery potential of in-depth gel systems in heterogeneous reservoir applications at high temperatures.
New Advancements in Mitigating Sand Production in Unconsolidated Formations
Authors: Kalgaonkar Rajendra , Chang Frank , Ballan Abdel N , Abadi Abdullah , Tan Xiaoyu 
Published: June 2017

Abstract
Sanding in oil production and water injection wells has been a severe problem in a sandstone formation. Many technical solutions have been evaluated by Saudi Aramco. These solutions encompass mechanical sand exclusion methods such as screen, gravel packing, and frac and pack. Various production and completion practices such as controlling the production rate and following specific well completion guidelines to minimize sand production have failed to provide satisfactory returns.
Several limitations such as screen plugging and costs associated with deploying expandable screens make the current mechanical sand control practices more expensive. Chemical sand consolidation could present the most cost-effective remediation and prevention opportunity. Additionally, this would also allow the wellbore to be free of tools, screens and pack sands.
With the cost benefit and technical challenges in mind, a new chemical system was developed to effectively consolidate loose sand, which has caused injectivity and productivity decline and costly clean out operations. The newly develop chemical system is based on resin backbone with a curing agent to harden under reservoir temperature. A permeability enhancing additive is incorporated in the system to achieve excellent and controllable regained permeability of the consolidated sand pack.
This paper presents the new advancements in preventing wellbore sand production. The newly developed sand consolidation chemical was studied for their ability to consolidate loose sand and at the same time maintain good permeability. The new sand consolidation chemical system showed several key advantages over the current commercial products, including its easy mixing procedure and superior performance in consolidation strength and regained permeability. It was shown that the permeability enhancer incorporated in the new sand consolidation product is the key to maintain superior regained permeability. In addition, it was shown that the new product provides a controllable curing time up to several days, thereby avoiding any premature setting of the resin in the wellbore. Furthermore, the new system is also compatible with acids to eliminate any post-job production issues if the formation is acidized in the future.
Success of Achieving Zero Discharge to Pit by Injecting in High Karst Shuaiba Formation in Umm Gudair Field
Authors: Al-Azmi Ali Abdullah , Tiwari Brajesh Kumar 
Published: June 2017

Abstract
Umm Gudair is the second largest field of West Kuwait Directorate. The majority of production in comes from Oolite reservoir. The production from the field began in early 1950's and as maturing of this field, the associated water production has significantly increased which has resulted in an environmental hazard in handling and disposing of the large volume of produced water.
West Kuwait Asset has two major producing fields which are Umm Gudair and Minagish. Water management in West Kuwait was designed to integrate all effluent water from gathering centers in West Kuwait through the Effluent Water Transfer System and the Minagish Water Injection Plant (MNWIP). All effluent water is transferred from the gathering centers through the Effluent Water Transfer System to the MNWIP for re-injection into the Minagish Oolite (MO) reservoir in the Minagish field (MN) for pressure maintenance. The re-injection of effluent water produced from WK fields into the Minagish Oolite reservoir of MN field has significant impact. Also, Mega disposal wells completed in the karsted Shuaiba formation as a back-up plan in case of any planned or unplanned shutdown of the MNWIP.
The success of many oilfields depends upon efficient disposal of produced water. A number of standard approaches were taken to obtain injection rates up to +20,000 BWPD per well on gravity feed. A multi-disciplinary team was formed to review the practical and theoretical aspects of formation damage and water quality. Successful injection at rates exceeding 60,000 BWPD per well were subsequently achieved by a proper completion design for the mega disposal wells and improving water quality.
This paper deals with the learning curve and dead ends that led to the successful subsurface disposal capacity of over 400,000 BWPD in High Karst Shuaiba Formation and achieving zero discharge to the pit. A holistic approach for monitoring and surveillance plan for wells with periodic review of current condition is adopted keeping cost effectiveness as an important parameter.
Jumping Mass Spectrometer
Authors: Rowe Mathew , Splapikas Tony 
Published: June 2017

Abstract
Current surface gas detection technologies are flawed in that they are limited in speed or can only detect certain gas types. Current gas detector technology does not provide a complete view of reservoir conditions without additional and costly inferred measurements from logging while drilling (LWD) or wireline tools. To overcome these limitations, a new instrument and methodology have been adapted from the chemical process industry and developed for drilling applications.
The initial goal was to develop a gas detection system capable of quantitatively analyzing more than 20 chemical species in less than 15 seconds. Several gas analyzers were reviewed for ruggedness, speed, accuracy, and chemical species detected. The system had to be capable of withstanding shipment to the rigsite and rigsite conditions. In addition, the system needed to be operable remotely to reduce personnel at the site. A gas chromatograph flame ionization detector (GC-FID) was used as the benchmark for accuracy and response.
A quadrupole mass spectrometer that would jump from mass peak to mass peak was selected. This spectrometer is characterized by an accuracy rate within 0.1%, a faster response time than a GC-FID, and the ability to analyze 32 chemical species in less than 10 seconds with drift less than 0.1%. The system was the best match to meet the initial goal. Developing a quantitative mass spectrometer proved to be a greater challenge. This objective was achieved by determining the chemical species fragmentation patterns and sensitivities at the base before deploying the system to the rigsite, where only a verification gas blend was necessary. The system can replace slower, qualitative mass spectrometers at the rigsite at a reduced cost with 10 times the data density.
The initial goal of developing a system capable of analyzing more than 20 chemical species in less than 15 seconds was achieved. Additionally, adapting instrumentation and methodology from the chemical process industry to drilling applications led to the development of a fully quantitative mass spectrometer at the rigsite with cycle times of less than 10 seconds for 32 chemical species.
Development Strategy Optimization for Different Kinds of Tight Oil Reservoirs
Authors: Hui Peng , Qiquan Ran , Yong Li , Yongjun Wang 
Published: June 2017

Abstract
Tight oil has large amount of resources and enormous potential in development. Application of volume fracturing on horizontal wells has a significant impact on tight oil development. But with continuing low oil price, development strategies should be more effective in order to maintain the economic development of tight oil reservoirs. This paper presents a case study of development strategy optimization for different kinds of tight oil reservoirs in China.
This paper focuses on MZ tight oil field in China. And reservoir properties and fractures of DAZ reservoir is better developed than that of LGS reservoir of MZ oil field. Based on geological understanding and dynamic characterization on the two formations, two representative sectors of each reservoir are selected. And corresponding geological and numerical simulation sector models are established. Finally, development strategies are optimized through reservoir simulation.
The optimized parameters include the length of horizontal section, well spacing, fracture segments spacing, fracture half-length, etc. Sensitivity analysis of all parameters are conducted based on the established simulation models. For DAZ reservoir, the optimized development strategies are: 2000m horizontal well length, 700m well spacing with 300m fracture half-length and 20 fracturing stages. While for LGS reservoir, the optimized development strategies are: 2500m horizontal well length, 800m well spacing with 350m fracture half-length and 22 fracturing stages. Although longer horizontal well and more fracturing stages for LGS reservoir, the predicted average well cumulative oil production within 10 years is still lower than that of DAZ reservoir because of the poorer reservoir quality of LGS reservoir.
This paper offers a case study on development strategy optimization for different kinds of tight oil reservoirs. The results have been applied to the two tight oil reservoirs in MZ tight oil field in China with successful results. It also provides a methodology and reference case for engineers and geologists to develop other similar fields.
Performance Analysis and Flow Regime Identification of Fractured Horizontal Wells in Tight Oil Reservoirs
Authors: Hui Peng , Qiquan Ran , Yong Li , Min Tong 
Published: June 2017

Abstract
Fractured horizontal wells are widely used to produce tight oil. But different fracture patterns could be generated in different reservoirs, which results in different well performances. How to identify the flow regimes and their impacts on performance is still challenging. This paper provides a method for flow regime identification of horizontal wells with different hydraulic fracture patterns in tight reservoirs.
First, four different fracture patterns of hydraulically fractured horizontal wells in different types of tight oil reservoirs are classified, according to the fracture network identified from micro-seismic observation and laboratory experiments. Then, corresponding well performances are simulated based on various conceptual reservoir simulation models. The simulation results are further used for rate transient analysis. Finally, flow regimes and corresponding production periods of each pattern are identified and classified, and well performances are also analyzed.
Flow regimes of different fracture patterns are identified based on rate transient analysis with input of reservoir simulation results. Different patterns have different flow regimes. For instance, there are linear flow, radial flow and boundary dominated flow in Pattern A, while bilinear flow, linear flow, radial flow and boundary dominated flow are prevail in Pattern C. The corresponding production phase of each flow regime is also classified. It can be seen that different scales of pores and fractures have different impacts on different patterns and production phases. In pattern A and Pattern D, large fractures determines the initial production rate and performance of linear flow, and more oil is produced in linear flow stage than in radial and boundary dominated flow periods. While in Pattern B and Pattern C, micro-nano fractures and pores are much more developed, which have more cumulative production and better performances during radial flow and boundary dominated flow.
The results are applied to the tight oil reservoirs in Junggar and Erdos Basin in China. Analysis of all fractured horizontal wells indicates that most are pattern A and Pattern B, and linear flow occurs in the early production period in all the patterns. If hydraulic fractures are long enough, bilinear flow could happen. Well performances are correctly predicted based on the well flow regime identification.
Reservoir Simulation History Matching and Waterflooding Performance Forecast for a Large Sandstone Reservoir in Middle East
Authors: Yong Li , Baozhu Li , Benbiao Song , Weimin Zhang , Qi Zhang , Xiong Lihui 
Published: June 2017

Abstract
For the same reservoir geological model, different simulation models could be obtained through history match calibration by different engineers. In other words, there are certain uncertainties within the calibrated simulation models. So how to reduce the uncertainty during history matching is still a problem. This paper presents how to quantify the waterflooding uncertainty and reasonably forecast waterflooding performance through reservoir simulation for a large multi-layered sandstone reservoir in Middle East.
Based on the results of detailed geological characterization, dynamic description and parameter uncertainty analysis, three fine geological models are built, which stand for upside model, expected model and downside model. Then parameter sensitivity on waterflooding performance is conducted based on sector model simulation, and waterflooding development strategies are also optimized. The results are firstly applied for the three full field model calibration by reservoir history matching. After that the calibration models are used for waterflooding performance forecast and the performance uncertainty are also quantified.
Take a large multi-layered sandstone reservoir in Middle East as an example. The MU reservoir is still under primary depletion with only 5% recovery currently, and waterflooding is urgent. Firstly, sector models are used for parameter sensitivity analysis and development strategy optimization. Then based on parameter sensitivity analysis results, the three full-field model are all calibrated with good history match. And different model calibration need different parameter adjustment, such as downside model has stronger aquifer support than that of upside model and expected model because of the poorer connectivity. So different models show different characteristics, such as most of west-south flank of MU reservoir are flooded for Downside model, while only some local area and some zones are water flooded for Expected and Upside model. Then waterflooding performance of different development plans are forecasted and compared based on the optimum development strategies and calibrated models. Furthermore, the performance uncertainty are quantified based on the three models.
This paper offers a methodology and a case study of reservoir simulation history matching in order to reduce uncertainty and better waterflooding performance forecast for a large sandstone reservoir in Middle East. Comparison of the three models can help to better understand the reservoir. And the results are valuable for the following development options decision making. It also provides a reference for performance forecast and uncertainty analysis of similar reservoirs.
Bit Wear Control and Optimization in Autonomous Rotary Steerable Drilling
Authors: Kamel M. A. , Elkatatny S. , Mysorewala M. , Al-Majed A. A. , Elshafei M. 
Published: June 2017

Abstract
Directional Steering System (DSS) has been established for well drilling in the oilfield in order to accomplish high reservoir productivity and to improve accessibility of oil reservoirs in complex locations. Rotary Steerable System (RSS) is the current state of the art in directional drilling. In this work, we address the problem of real time control of RSS with unknown formation friction and rock strength. The work presents an online control scheme for real time optimization of drilling parameters to (1) maximize rate of penetration, (2) minimize the deviation from the planned well bore trajectory, and (3) assess the degree of bit wear. Nonlinear model for the drilling operation was developed using energy balance equation, where rock specific energy is used to calculate the minimum power required for a given rate of penetration. The bit wear is mathematically represented using Bourgoyne model. Detailed mathematical formulation and computer simulation were used for evaluation of the performance of the proposed technique, based on real well data. The obtained results showed excellent ability to accommodate the changes in the formation properties. In addition, the rate of bit wear has been optimized.