bluuebunny/crossref_metadata_2025_split huggingface dataset:
Creating Variance Cube from Seismic Data and Converting to Transmissibility Multiplier Pattern to Assist History Match
Authors: Gao John , Schrijver Bart 
Published: September 2015

Abstract
This paper demonstrates how to utilize seismic data to create a variance cube with different values and convert it into a transmissibility multiplier pattern to assist the history match in dynamic simulation.
Lateral variations of the seismic signal can be related to various reasons, such as faults respectively associated fault damage zones and sedimentological bodies like channel features. Dissimilarities within the seismic data can be emphasized by calculating a variance attribute. The different value ranges within the variance cube can in the chosen examples be associated to the fault plane itself and different intensities of fault related rock alterations or channel characteristics, e.g. erosional planes. These features can result in improved or reduced lateral transmissibility as poor or good rock properties coincide with poor or good transmissibility for fluid flow. The variance value patterns can be analyzed and categorized according to the discrete value ranges. Then the categories are converted to reference numbers, e.g. variance reference number 1 represents a good transmissibility (e.g. a channel body), 2 represents reasonable and 4 represents the poorest class (e.g. an intense faulted zone). Subsequently the variance reference number is converted to a transmissibility multiplier value. During the history match process, these multipliers are adjusted in order to improve the history match.
The advantage of this approach is that it does not only change the transmissibility multiplier in one cell, but changes the transmissibility multiplier value of each cell that belongs to one type of rock quality (one variance reference number or one transmissibility group) in one calculation. This is especially useful where there is limited history data and the variance data indicates similar patterns throughout the variance cube. This method can speed up the history matching as it is a batch change of transmissibility multipliers, similar to the fault transmissibility multiplier method in ECLIPSE but with a wider application. In a case study a comparison was conducted with using the variance cube / transmissibility multiplier patterns and confirmed the method workable.
In conclusion using the variance cube to create transmissibility multiplier patterns is an efficient way to assist and improve history matching, especially in fields with limited well control.
This paper presents a new way of creating transmissibility multipliers based on seismic data (variance attribute) and assisting and improving the history match process
Minimization and Removal of Wellbore Storage Effect by Direct Deconvolution of Well Test Data
Authors: Dastkhan Zohrab , Zolalemin Ali , Razminia Kambiz , Parvizi Hadi 
Published: September 2015

Abstract
Wellbore storage effect is a common issue in pressure transient analysis which masks the early response of reservoir behaviour and flow regime. It distorts most of valuable pressure data especially in cases with large well volume, high mechanical damage, and compressible fluids. As a consequence, the early response of fast-occurring phenomena such as dual porosity transition, linear flow and bilinear flow can be partially or completely distorted.
In this paper, a procedure is proposed and applied to enhance the applicability and effectiveness of direct deconvolution methods for calculation of wellbore storage-free pressure response. The proposed procedures are tested and validated in large-volume wells in the Middle East where wellbore storage has distorted the whole well test data points. We found that these methods can be followed to identify early flow regime types and to calculate permeability, skin and natural fractures properties with the lowest uncertainty.
High-resolution Sequence Stratigraphy Research on the Western Slope Area, Songliao Basin, North-eastern China
Authors: Liu M. H. , Hou Z. M. , Deng H. W. 
Published: September 2015

Abstract
At present, the study on subtle oil and gas reservoir is being focused on one of the Chinese biggest petroliferous basins-Songliao basin, where the Chinese biggest oil field was found. Therefore, the western slope area, a significant reserve increment and replacement area in Songliao Basin, has become one of the most important targets in subtle oil and gas reservoir exploration and development. Nevertheless the stratigraphic framework and sedimentary microfacies in this area are still ambiguous. Combining cores analysis, well logging and 3D seismic data with theory of high resolution sequence stratigraphy, the sequence stratigraphic frame from the first member of Formation Yaojia to Formation Nenjiang in study area is constructed. Moreover, the monosandbody high resolution sequence stratigraphic framework is established, meanwhile the monosandbody isochronic correlation is achieved in the isochronic stratigraphic framework. Finally, through an improved approach to the high resolution sequence stratigraphic analysis, the stratigraphic framework of the western slope area is established, which is helpful to locate exploration and development aims, and to identify the sedimentary microfacies and reservoirs characteristics in the study area. This research also plays an important role in the further study on subtle oil and gas reservoir in the Songliao Basin in China.
A Comparison of Permeability Prediction Methods Using Core Analysis Data
Authors: Ngo Vuong Thanh , Lu Vi Dinh , Nguyen Minh Hong , Hoang Tan Manh , Nguyen Hung Manh , Le Vu Minh 
Published: September 2015

Abstract
Permeability is one of the most important parameters of reservoir rocks, it illustrates the capacity of rock to transmit fluids (oil, gas, water) in pore spaces. Permeability data can be obtained from routine core analysis in laboratory on 1.5 in plugs and sidewall core. However, coring is limited due to cost issue, so permeability prediction in uncored sections play a significantly important role. The variety of methods developed to estimate permeability using pore scale such as Kozeny-Carman, Swanson and Pittman. In fact, those equations are applied individually to estimate permeability. In this research, permeability estimation methods will be used on the same rock (sandstone or carbonate rock) to detect the suitable method for each rock type.
Porosity, permeability data from routine core analysis and pore throat size from mercury injection capillary pressure on sandstone and carbonate rocks from Cuu Long and Song Hong basins in Vietnam will be gathered and permeability estimation conducted by using Hydraulic Flow Unit (HFU), Mercury Injection Capillary Pressure (MICP) and Pittman methods based on that data. Estimated permeability obtained from each methods will be compared with core permeability, the method with the highest R-squared be selected.
The research shows that Hydraulic Flow Unit is the most suitable methods for permeability prediction on sandstone with R-squared &gt; 0.9. On the other hand, mercury injection capillary pressure is the most accurate method to estimate permeability on carbonate rocks related to heterogeneity and complicated pore system. That results will help engineers have a fast and accurate decision for permeability prediction methods selection on sandstone and carbonate rocks.
In addition, the empirical equations were derived to predict permeability on sandstone and carbonate rocks with the highest coefficient of correlation in multiple regression analysis and based on the relationship between porosity, permeability and pore throat size.
Characteristics and Genesis of Low to Ultra-Low Permeability Carbonate Rocks: A Case Study in Late Cretaceous Sadi Formation in H Oilfield, Southeast of Iraq
Authors: Han H. , Zhao L. , Xu X. , Lu W. 
Published: September 2015

Abstract
The Santonian-Campanian Sadi Formation carbonate reservoir of the late Cretaceous in H Oilfield located in SE Iraq has been proved to be an oil-bearing stratigraphic unit with medium porosity and low to ultra-low permeability, which increases difficulties in producing oil contained in carbonate rocks. In order to forecast the favorable reservoir with higher production rate, it needs to study the characteristics and genesis of this reservoir. Data used includes a total of 236m cores from 4 wells. Firstly, microfacies interpretations were supported by log interpretations and core descriptions. Then, diagenesis processes were analyzed according to thin sections. Next, relationship between microfacies, diagenesis process and reservoir characteristics such as porosity, permeability, pore types and pore-throat characteristic were investigated. Finally, favorable reservoir characters and the genesis of reservoir in this formation were obtained. Sadi Formation represents a third-order depositional cycle composed of limestones and marlstones containing planktonic foraminifera and bioclastic debris together with extensively bioturbated argillaceous rocks, depositing on a ramp setting. Foraminifera limestone in middle ramp experienced syngenetic diagenesis and burial diagenesis, ultimately evolved into low and ultra-low permeability reservoir with intrafossil pores and micro pores. Shapes of pore throat distribution of middle ramp rocks represent thin and single peaks. Bioclastic limestone in inner ramp shoals experienced marine pore-water diagenesis, meteoric fresh water dissolution and burial diagenesis, ultimately evolved into low permeability reservoir with dissolution pores, mouldic pores and micro pores. Shapes of pore throat distribution in inner ramp shoal rocks represent irregular peaks, with wide range distribution. The favorable reservoir exists in intraclastic shoal sediments deposited in inner ramp. Results of this paper contribute to further understanding of the sedimentary and reservoir characters of Late Cretaceous Formation in SE of Iraq, and benefit for favorable reservoir predicting and oil producing in this oilfield.
Giant Carbonate Reservoir Study Showing Impact of Capillary Pressure Hysteresis on History Match & Field Development Plan
Authors: Ismail Ahmed M. , Kalam Mohamed Zubair , Jasser Majdolin Hanna 
Published: September 2015

Abstract
Numerical modeling of mixed wet reservoirs with a thick transition zone typically requires full hysteresis option to be invoked in the reservoir simulator. In this super giant carbonate reservoir with multi-million active cells and twelve reservoir rock types, running the full hysteresis option proved prohibitive due to excessive run times, and in many cases the run fails. Traditionally, engineers resorted to generating scanning curves that mimic the hysteresis option manually using algorithms or spreadsheets. Going further back in history, engineers used imbibition curves which tend to overstate water production. This paper aims at presenting the underlying methodology of developing water-oil capillary pressure scanning curves for mixed wet super-giant carbonate reservoir and to show how significantly this improved the history match quality of water flood and development plan for EOR as well as optimizing the 3D simulation run time.
To develop the appropriate bounding and scanning water-oil capillary pressure curves, Killough Hysteresis model was used. To ensure that the algorithm of this model resulted in reliable scanning curves, commercial simulator sector model was built and the resulted scanning curves from this sector model compared with the mathematical approach used to generate scanning curves over a wide range of water saturation. Validation between full hysteresis option and scanning curves for each Reservoir Rock Type (RRT) was also carried out on simple 1-D & sector models before use of the scanning curves in the full field model.
The scanning curves methodology involved (i) setting up Hysteresis based 1-D model for each RT (ii) assigning initial water saturation in each cell between Swi and Sor and initial pressure for each rock type (iii) run the model for a long time to span the saturation range (iv) iterate on time step (TSTEP) to get smoother scanning curves (v) filter the scanning curves get reduced data points (v) ensure the Krw curves were not crossing the drainage curve for each rock type (vi) created another 1-D model and used scanning curves and (vii) validated the results with use of full Hysteresis options.
Using full hysteresis saturation function curves show significant improvement in the history match quality especially in transition zone where it was difficult to match the flood front with the normal saturation function. It is worth to mention that using scanning curves (121 curves was the optimum number of scanning curves) showed reduction in the simulation run times as compared with the full hysteresis option.
Improved Reservoir Management Decisions Using Ensemble Based Methods
Authors: Jon Sætrom , Klemens Katterbauer , Tore Munck 
Published: September 2015

Abstract
In today's market situation it is becoming increasingly important to minimize the risk of making poor investment decisions. Reservoir models, and associated model predictions are often used a direct input in these decisions. Hence, it is of utmost importance that reservoir model predictions and associated uncertainty estimates can be trusted. In order to achieve this task, a clear requirement is that the reservoir models consistently honour both static and dynamic data, while capturing all modelling uncertainties. In this paper we will illustrate how using ensemble based methods can ensure both fast and consistent data integration and give an improved representation of the model and prediction uncertainties, leading to improved reservoir management decisions. Furthermore, we illustrate that the traditional, base case, approach leads to the wrong investment decision as model uncertainties are ignored.
Heterogeneity Characteristics of Carbonate Reservoirs: A Case Study using Whole Core Data
Authors: Wei Chenji , Tian Changbing , Zheng Jie , Cai Kaiping , Du Dong , Song Benbiao , Hu Yunpeng 
Published: September 2015

Abstract
Carbonate reservoirs have complex pore structures and serious heterogeneity, which increase the difficulty to achieve efficient oilfield development. Conventional core plugs cannot accurately depict the heterogeneity characteristics that may beyond the scale of plugs. Thus, whole core experiments are conducted to better study this issue.
The methodologies involved in this study include experimental study, outcrop observation, statistical analysis, and numerical modeling. 18 whole core sections are collected from a giant cretaceous carbonate reservoir located in the Middle East, and the OOIP of this carbonate is 4000 MM bbls. We conducted 3D CT, whole core experiments, and plug experiments for the total of 18 sections of the core. Furthermore, numerical simulation is conducted to better evaluate the impact of heterogeneity.
After integrating results from all these methodologies and technologies, 2D and 3D CT images, horizontal permeability, vertical permeability, and density of whole core, horizontal plug, and vertical plug are obtained. Then, pore structure visualization and experimental results are combined, and analysis was carefully conducted. Results show that whole core can better depict the reservoir heterogeneity, and some interesting observations were found, such as when the permeability of the core section is low, permeability of whole core is greater than that of plugs; whereas when the permeability of the core section is high, permeability of whole core is lower than that of plugs. Simulation results indicate that heterogeneity is one of the major factors determining the performance of carbonate reservoirs.
This study offers detailed evidence to support engineers and geologists for better understanding the heterogeneity and optimizing production plan on the carbonate reservoir.
Future Trends for Tight Oil Exploitation
Authors: Zhang K.. , Sebakhy K.. , Wu K.. , Jing G.. , Chen N.. , Chen Z.. , Hong A.. , Torsæter O.. 
Published: September 2015

Abstract
In this paper, production characteristics of tight oil reservoirs are summarized and analyzed, the investigated reservoirs include Cardium sandstone reservoir and Pekisko limestone reservoir. The phenomenon that gas and oil or water and oil are co-produced at an early stage of exploitation has been observed. In addition, water cut of many tight oil producers remains constant or undergoes reduction as production proceeds within first 36 months.
Since an oil rate drops quite a lot in the first year's production of tight oil reservoirs, reservoir simulations are run to investigate an effect of different parameters on tight oil production. Randomized experiments are created with geological and engineering parameters as uncertain factors and an oil rate as the response factor. The method of analysis of variance (ANOVA) is used to analyze the difference between group means and to determine statistical significance.
Reservoir properties such as permeability, pressure, wettability, oil API, and oil saturation and engineering parameters including a fracture stage and well operations have tremendous effects on oil production. Oil recovery factor increment in tight oil reservoirs highly depends on enlarging a contact area, improving oil relative permeability, reducing oil viscosity and altering wettability. Future research and development trends in tight oil exploitation are highlighted.
As primary recovery is quite low in tight oil reservoirs, the multistage fracturing technology is a necessity and it must be conducted based on a deep understanding of petrophysical and geomechanical properties. Water alternating gas (WAG) seems the best fit for tight oil exploitation. The way to improve WAG performance, including CO2 foam stabilized with surfactant or nanoparticles, low salinity water or nanofluids alternating CO2, will earn more and more attention in the future of tight oil development.
Nitrogen Injection as IOR/EOR Solution For North African Oil Fields
Authors: Heucke Ulrich 
Published: September 2015

Abstract
Nitrogen injection is a proven technology for Improved and Enhanced Oil Recovery. This paper explains the recovery mechanisms and infrastructure requirements, and highlights its advantages as a low cost and water saving process for the arid North African region. A case study from Cantarell/Mexico demonstrates its applicability. The assessment of oil fields in Algeria, Egypt, Libya and Tunisia shows the potential of the technology for the North African region.
Nitrogen injection can be used for gas cap pressure maintenance, immiscible or miscible drive of oil fields. The technologies for nitrogen production by air separation and for nitrogen rejection from associated gas are explained. A case study of nitrogen injection is shown. The capital expenditure and consumption figures are given. A screening method for North African oil fields is explained, including the oil and reservoir screening criteria, as well as ratios for nitrogen demand and incremental oil production.
Nitrogen is produced from air, and therefore universally available as an inert and low cost injection fluid. The technology can be used in onshore and offshore environments, and especially in areas where water is scarce. The case study of nitrogen injection in the Cantarell oil field in Mexico shows the positive production result of nitrogen injection. The assessment of North African oil fields shows a very good potential for the application of the Technology. A total of 48 oil fields in Algeria, 49 fields in Egypt, 50 fields in Libya and 19 fields in Tunisia have been identified with good potential for nitrogen injection with up to 10% incremental recovery factor of the Original Oil In Place.
The paper summarises the foundations of nitrogen injection for Improved and Enhanced Oil Recovery, especially with a focus on the surface related technology installations for the North African region. The oil field assessment including injection result estimate and nitrogen capacity requirements is new for the region and in the literature.
Dynamic Temperature Modeling for High Temperature Well Planning
Authors: Suryadi Hendrik , Bolchover Paul , Miguel Dennis 
Published: September 2015

Abstract
The search for new reserves is pushing drilling into deeper reservoirs where formation temperature becomes a challenge. This becomes significantly challenging with current available drilling tools where the operating temperature can closely reach and at times surpass the downhole tools’ temperature specifications. Service companies are continuously improving technology to increase the temperature limit of the downhole tools to contend with the increasing temperatures; however, the ability to simulate downhole conditions and predict downhole circulating temperatures that the tools will be exposed to continues to be a key factor to successful drilling operations in high-temperature wells.
The current well-planning practice of designing high-temperature wells is based on static formation temperature measurement from the offset well and linear interpolation of the formation thermal gradient, which, in many cases, is too conservative, not taking into account various parameters that affect the total energy within the system that leads to the actual temperatures that the downhole tools are physically exposed to. Heat transfer occurs from the formation across the mud and downhole tools. Mud circulation carries mud with heated temperature from the bottom of the hole up to relatively cooler temperature as it approaches the surface, and back down the hole again; this will affect the actual downhole temperature that the tools are exposed to. Energy loss of torque and drag due to contact friction of drillstring with different formation and hydraulic pressure loss can also increase the borehole temperature and downhole tool temperature. A new state-of-the-art dynamic temperature model is required to more precisely predict downhole temperatures and which can be used to guide the downhole tool and services planning, along with operating parameters to be applied. This information is needed to be able to run as many downhole tools and measurements in real time to the tool temperature limit and reduce nonproductive time (NPT) due to pulling out of hole for temperature-related downhole equipment failures.
Dynamic temperature modeling takes heat transfer from virgin formation to mud and tool collars into account, while also calculating the effect of circulation, mechanical, and hydraulic friction. The dynamic temperature model can help engineers evaluate expected temperatures for different operations, guiding them to select the appropriate downhole tools for the job. The modeling was used in planning several case study high-temperature wells, and a comparison was done between model results and actual downhole temperature measurements.
This new modeling can change the high-temperature well planning perspective on the use of downhole tools in that a higher temperature rating (e.g., above 150°C) is not always required because downhole borehole temperature can be managed by applying the right drilling parameters and correct timing.