bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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 > 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

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

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

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

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

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

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

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.
The Lateral Migration of the Serravallian Turbiditic Reservoir Bodies in Temsah Concession, Offshore Nile Delta, Egypt and its Impact on the Explorative Potentail in the Area
Authors: Ibrahim M. A. , Zaki A.. , Avella A..
Published: September 2015

The study area covers Temsah concession in the eastern sub-basin, offshore Nile Delta, Egypt.

Despite the Serravallian play within this area is proven, observations made on recently acquired seismic data suggest its potentiality might be significantly larger than initially evaluated.

Over 25 wells have been drilled within Temsah Development Lease since late 70's targeting turbiditic channelized flow deposits fitting a part of the four way dip closure Akhen-Temsah anticline.

The interval of study shows a general fining upwards GR log pattern with a sub-parallel thinning up-dip seismic reflectivity.

Amplitude map analysis through this interval shows southwest-northeast anomaly trends, shifting upwards to the southeast and becoming thinner and narrower.

New hydrocarbon potential arises under the assumption that reservoir rock distribution is restricted to the anomaly trends mapped on the over-laying levels, from those producing from the main field area, and located down-dip on the southeastern flank of the structure. The associated risk derives from the reservoir architecture and possible lateral up-dip communication to underlying beds through permeable beds.
Fracturing Fluid Rationalization: First Dual-Viscosity Fracturing Fluid Application in the Middle East
Authors: Mira Ali , Samir Mohamed , Naby Mohamed Abdel , Mohamed Nelly , Rojas Jose , Kamar Ahmed , El Sebaee Mohamed
Published: September 2015

Dual-viscosity fluid is a fracturing fluid that has been recently introduced to cover a wide range of fracturing applications varying, from a non-delayed to delayed fluid system for treatments in low to moderate to high temperatures, respectively. Reducing the impact of the pressure effect of traditional borate cross-linked systems, the system crosslinker is compact and delivers a relatively high concentration of crosslinker per unit volume; it is also compatible with current metering pumps, covering a range of treatment rates compared to the current fluid system, and this can simplify logistics on location.

The North Bahariya oil fields are onshore fields located in the Western Desert of Egypt and operated by Sahara Oil and Gas Company (SOG). The fields contain proven oil reserves in two sandstone packages at relatively shallow drilling depths (6,500 ft. subsea) in the Abu Roash "G" member (A/R G) of Cenomanian (Cretaceous) age. These sandstones comprise the main reservoirs in the field. During the last 4 years, the introduction of various techniques has led to a fourfold increase in the production from these fields. This success story is mainly the result of using the new hydraulic fracturing methods such as channel fracturing technique and continuous improvement of the fracturing treatments. SOG has been at the forefront in applying novel technologies to optimize the fracturing fluid treatment by using the dual-viscosity fracturing fluid to improve the wells potential.

This technology has been implemented in Abrar field. As seen in case studies, very positive results have been seen in both zones of the A/R G formation in terms of improvement in the well performance.

Experiences in Abrar field illustrate how to optimize the production rate in a marginal field by optimizing the hydraulic fracturing treatment fluid and how to build on this success for subsequent fields while pushing the innovation envelope further.
Gulf of Suez Integrated Gas Lift Optimization Study
Authors: Hamshary Adham , Sheta Ibrahim , Basha Kareem , Atteiya Mohamed , Davies Nick , Girgis Fady , Fouad Raed , Kamal Mohamed
Published: September 2015

The Gulf of Suez Petroleum Company (GUPCO) is a leading Egyptian petroleum company. GUPCO production is primarily dependent on gas lift with 90% of its producing wells utilizing this artificial lift method, consuming more than 450 MMSCF of gas per day. One of the main hindrances to maximizing GUPCO's production is insufficient gas supply which leads to shutting in many producers resulting in significant production deferrals.

GUPCO's Base Management Team (BMT) initiated an integrated system optimization project in 2013 which combined four different technical pieces of work. It was introduced for the first time in GUPCO to ensure gas is used efficiently in the Gulf of Suez (GoS) to maximize the value of GUPCO's old data, build trust in well and surface modelling and increase BMT capabilities. The main challenges of this project were data gathering and quality, engineering capabilities in the use of Prosper and GAP modelling and lack of integration between field and office technical personnel regarding the system optimization.

Working through these challenges created tangible value through enhanced understanding of the gas sy stem, identifying additional opportunities to save gas and increased oil production. This boosted the modelling capabilities of all team members. The BMT approach was divided into four different phases as follows: Gas balance study for better understanding of the gas systems in the different areas across the GoS.Prosper modelling for gas-lifted wells that resulted in 20 gas lift valve change opportunities that lead to increased production of 1000 BOPD.GAP modelling for the production system that resulted in a 7700 BOPD potential oil gain, 16.5 MMSCFD potential gas saving and debottlenecked pipelines.Creaming curves which became a very good tool to prioritize the GL wells with respect to gas availability, evaluating well work value, and quantifying the impact of surface facilities failures and/or repairs.

Until the time of this paper, the project was in the execution phase and has resulted in saving 7 MMSCFD from optimizing gas lift injection in 8 wells. The forward plan of the project is as follows: Continue the execution phase and ensure good communication between all teams.Install recommended meters/scanners to enhance data measurement in order to ensure sy stem balance.Complete GL optimization execution in SC GoS & share the outcomes.Install MPFM on some offshore platforms which will help in evaluating the optimization.Utilize a Portable Test Package for further enhancement of system evaluation & optimization.

The objective of this paper is to show the technical processes used to initiate an integrated gas lift optimization project in the GoS and how the opportunities created will add considerable benefits to the business.
Poroperm Characterization and Rock Typing of Tight Carbonate Reservoir Using Core Calibrated Image Perm Technique: Turonian Carbonates in Abu Sennan Field, Western Desert, Egypt, A Case Study
Authors: Helba Adly , Ali Wael , Fattah Mohsen Abdel , Mokhtar Hesham , Farouk Mona
Published: September 2015

The recent achievement in unconventional reservoirs has established the objective of reevaluating the oil-bearing tight carbonates as potential oil production reservoirs. Of these carbonates, the Turonian Abu Roash D (AR/D) tight limestone in the Abu Sennan field of the Western Desert, Egypt contains oil, but has extremely poor recovery. The challenge in this study is to define the effective parameters that control the various petrophysical attributes of this tight reservoir and their influence on reservoir recovery.

Integrated sedimentological analysis and poroperm characterization was performed based on various data sets, including conventional core analysis, mercury injection tests, and petrographic inspection. A core-calibrated image-perm software algorithm was processed to evaluate the heterogeneity of reservoir pore system and to provide a continuous and azimuthal output of high resolution porosity and permeability.

The AR/D limestone succession (approximately 82 m thick) consists almost entirely of offshore-outer ramp bioclastic wackestone-mudstone facies, with the exception of a reduced reservoir-forming interval (approximately 10 m thick), which consists of inner- to mid-ramp facies. The outer-ramp offshore facies have very poor reservoir quality, with total porosity of less than 9% and permeability values that never exceed 0.1 mD. The reservoir-forming interval begins with storm beds of whole fossil rudstone and bioclastic wackestone, and gradationally terminates upward with inner-ramp shoal beds (5 m thick) of benthic foraminiferal peloidal packstone. The shoal facies measure a noticeably enhanced porosity (15 to 27%) with a relative increase in permeability (up to 2.3 mD). However, a petrographic inspection with resistivity image analysis showed a clear paucity of visible mega- and meso-pores or significant natural open fractures. This means that the reservoir pore system is of the intercrystalline microporosity type, which is confirmed by scanning electron microscope (SEM) and the measured pore throat radii ranging between 1 and 0.005μ. The prevalence of microporosity in the best zone of AR/D reservoir is also evident by a unimodal porosity range distribution shown by an image-perm output. This homogeneous and volumetrically significant microporosity nature may provide a favorable recovery if a suitable fracturing design is applied.

This study highlights the effect of microporosity types on the permeability of tight limestone reservoir, and emphasizes the workflow and benefits of the image-perm technique in evaluating the poroperm system and heterogeneity in the porosity distribution in carbonate reservoirs.
Multi-Well Correlation to delineate Stacked-Channel Reservoir using High Resolution Micro-imaging Facies
Authors: Hassan Sahar S. , Megawer Abdel Khalek , Zahran Hemida , Emam Mahmoud , Abu El Fotoh Ahmed M. , Haddad Elia
Published: September 2015

The Western Desert accounts for approximately two thirds of Egypt's surface area. The region can be divided into a number of large scale structural provinces which developed along lines of weakness in the African basement, in response to lateral movements between Europe and Africa. Seismic evidence has revealed a subsurface comprising a series of low relief horsts and grabens. In places however, the structural history is more complex.

The Yusif field located near the Qatara depression, is habituated and, therefore has poor seimic data. Three wells were drilled in the field, Yusif -1X, Yusif-3, and Yusif-4 respectively. The fourth well is planned for the most promising area between the three wells. Formation microimaging was performed in the three wells, and interpretation of the images helped to delineate the sand body propagation and geometry in the field and choose the most promising area for drilling the fourth well.

The Lower Abu Roash “G” member usually appears as a fining upward profile from conventional openhole logs. Facies analysis was performed on the “G” member with manual sedimentary dip picking, which revealed the internal structures and directions that can't be observed from conventional logs.

Correlation with existing openhole logs showed continuity in the vertical and lateral distribution of the sand body, and queries about the relation between the sand bodies in the three wells arose. The relationship between sand bodies can't be solved by conventional openhole logs correlation.

Paleocurrent analysis was performed for the sand bodies in the three wells. The results showed that the main trend of the channel belt propagation is NE. Yusif-3 and Yusif-4 wells were drilled within the channel belt while Yusif-1X location was at the channel margin.

Correlation is based on electrofacies, which was extracted from high-resolution formation microimaging in the three wells. It was found that the “G” member top is changed based on high-resolution electrofacies detection, and the fourth well was placed closer to Yusif-3 and Yusif-4 based on the recommendations on the channel activity propagation as identified in the formation microimaging. The sand body thickness in the fourth well was almost double the thickness that was found in the previous three wells.
Electric Submersible Pumps as an Artificial Lift Solution for Complex Wells Operation in a Caspian Sea Offshore Oil and Gas Field
Authors: Berdiyev Yunus , Kortukov Dmitry , Atabayev Dovletgeldi
Published: September 2015

Dragon Oil needed to extend the production lifecycle for it's offshore field wells with lower than expected natural flow regime duration. After reviewing multiple of running the Electrical Submersible Pumping options, Dragon Oil chose to implement tubing conveyed and rigless ESP's to return the candidate wells to the required production levels. This case study highlights the technological rational, challenges in implementing decided strategy and prognosticates expected results & benefits from running the two types of ESP's as an additional well investments. Candidate wells for ESP Artificial Lifting have been drilled from offshore wellhead platforms “1” and “2” into the flanks of the Main Field Reservoirs. Commissioning of the pilot ESP projects is expected by end of 2015.
Effective Fracturing Stimulation in the BRN Field in Algeria Using a Residue Free Gelled Fluid System
Authors: Forno Luca Dal , Latronico Roberto , Mohammed Omar , Kateb Mahmoud , Rispler Keith , Ainouche Dalil , Squires Scott , Petteruti Ernesto , Fragola Daniele , Allal Mohammed A. , Hachelaf Houari , Albani Danilo , Hamdane Toufik , Carpineta Gabriele
Published: September 2015

Hydraulic fracturing for well performance optimization has been implemented for many years in BRN field in north-eastern part of Algeria, operated by Groupement Sonatrach-Agip (a JV between ENI and Sonatrach). Because of unfavorable petro-physical properties of the reservoir, some challenges have been encountered in avoiding any additional damage to the fracture faces and to facilitate the post-job treating fluids flowback. Effective fracturing treatment designs should consider preventive actions for possible fracture conductivity impairment, such as damage attributed to stress, proppant embedment, and damage caused by fracturing fluid residues. Correct proppant selection can minimize effects from stress and embedment, while a suitable fluid system can minimize conductivity impairment from gelling agent solid residue.

Traditional guar-based fluid systems, which are often a preferred choice in the industry for fracturing operations, can have damaging effects on fracture conductivity attributed to inherent insoluble residue that can plug proppant pack pore spaces. Implementing a less damaging fluid system can not only maximize retained conductivity, but furthermore provide longer effective fracture half-lengths which may result in more efficient treatment fluid recovery. Therefore, to overcome such issues, a new fracturing fluid has been developed, leaving little or no residue after breaking. Moreover, this fluid system can be tailored to a wide variety of bottom-hole conditions and has comparable properties to guar-borate fluids with respect to proppant transport capacity and rheological characteristics (e.g. viscosity building and breaking behaviors).

This paper presents the first successful implementation of this novel fluid system in the BRN field in Algeria for improving the water injection performance of a well characterized by a tight sandstone reservoir. Field data collected after performing the propped fracturing treatment confirm the effectiveness of the fracturing fluid design. Specifically, the following topics will be extensively described within this paper: Characteristics of the BRN field and history of conventional guar-base fluid systems used previously within this field;Specifics of the near residue free fluid system (cross-linker types, pH requirements, etc.);Design considerations for the implementation in the BRN field of this novel fracturing fluid;Results of post fracturing water injection performances.
Proper Selection of Multiphase Flow Correlations
Authors: Abd El Moniem Mohamed. A. , El-Banbi Ahmed H.
Published: September 2015

Multiphase pressure drop calculations represent a challenge for petroleum engineers. We normally rely on multiphase flow correlations to calculate pressure traverses through tubing from the sand face to the wellhead. Although there are many multiphase flow correlations covering most flow conditions; there are still no clear criteria to select appropriate correlations in absence of flowing gradient survey data.

The objective of this work is to help petroleum engineers select the most accurate multiphase flow correlation(s) for any flow conditions, fluid properties, and well configuration.

The method depends on analyzing a large database of pressure drop data from many wells. Our database is composed of more than 3,200 measured pressure points taken from survey and single point measurements on 879 wells representing large variations of flow conditions (oil rate ranges from very low rate to 31,000 BBL/D, water cut from 0 to 98%, gas-oil ratio from 0 to 20,000 SCF/STB, gas rate from very low rate to 200 MMSCFD, water gas ratio from 0 to 200 BBL/MMSCF, condensate gas ratio from 0 to 200 BBL/MMSCF for vertical, deviated and horizontal wells with different tubing sizes).

We built models for all these wells and tested many available multi-phase flow correlations and recorded the error in their prediction against the actual measurements of pressure points. We then classified the large database into groups and found all multi-phase flow correlations within this group that have the lowest error. For every group, we can now identify the best correlation(s) with their estimated error value. We also defined a term to reflect the strength of the appropriate correlation(s) (how many times this particular correlation was best in each group of data) to help engineers select appropriate correlation for each well and its flowing conditions.

The strength term for all groups varies from 100 % to 30% which indicates that for several groups we can now select the multiphase flow correlation with significant accuracy. The expected error for all correlations is also reported. The parameters that mostly affect each correlation are also highlighted so engineers would know which parameters need to be accurate in using the recommended correlations.
Drilling Optimization in Achimov Horizontal Wells by Integrating Geomechanics and Drilling Practices
Authors: Dymov S.. , Kretsul V.. , Dobrokhleb P..
Published: September 2015

A workflow was developed for effectively handling the development challenges in the Yamal oil and gas province of Western Siberia. The workflow integrates geomechanics with efficient drilling practices and leads to the implementation of an engineered drilling system (EDS).

The workflow for development in the Yamal region encompasses phases from modeling to drilling practices, incorporating an understanding of challenges faced and lessons learned from previous drilling. The majority of Achimov operations in the Yamal region have been conducted in the Urengoy gas condensate field, which is divided into different blocks. The Achimov deposits are deep (true vertical depth is about 3,750 m), exhibit abnormally high formation pressure (over 600 atm), and contain multiphase hydrocarbons with the presence of heavy paraffins. Unstable shale formations must be drilled prior to penetrating the Achimov itself. These challenges affect drilling efficiency and interfere with the well construction schedule. The Achimov formations present two main challenges to horizontal drilling: wellbore instability leading to stuck pipe incidents in the build section or inability to run liner/casing to total depth and loss circulation, potentially compromising well delivery and project objectives. Thus, previous drilling has shown that developing and producing from these enigmatic resources requires more than just horizontal wells and hydraulic fracturing.

Companies are aggressively pursuing Achimov deposits, hoping to extract additional gas and gas condensate volumes from the declining fields and to implement a strategy to raise natural gas production. Successful operations require an integrated approach, using multiple data sources, to determine the key parameters needed to understand the Achimov formations and extract the hydrocarbons. Among the successes, an operator company for Urengoy field demonstrated how developing a mechanical earth model (MEM) of the reservoir and continually improving processes paid big dividends.

By implementing the EDS approach, unique results have been achieved in drilling and completion of Achimov horizontal wells. Outstanding drilling performance in Achimov horizontal wells has led to a revision of the field development plan.
Prediction of True Resistivity and Resistivity index using Neural Networks with Different Combinations of Wireline Logs
Authors: Sbiga H.. , Mousa N..
Published: September 2015

This study has been undertaken in two oil fields (A-Libya, and B-Libya) in Sirte basin located in Libya. Nubian sandstone Formation is the main reservoir in the studied oil fields. Laboratory resistivity measurements were performed at Libyan Petroleum institute (LPI). The majority of wells, however, are logged and the use of wireline log data in conjunction with some core data has been proposed as a rapid, cheap, and alternative to predict some special core analysis (SCAL) parameters instead of collecting extensive core or performing SCAL measurements in all wells. Neural network predictors are potentially very useful in the present study due to the limited SCAL data for the studied wells. In this work some of SCAL parameters were predicted using neural networks based on different combinations of wireline logs. The procedure firstly involved training the neural network predictors using data in training well A-02. These predictors were then applied to an adjacent well A-01 in the same oil field, and to another test well B-01 in a different oil field. The most frequently used type of neural network is a feed forward neural network using a back-propagation learning algorithm, due to its popularity and simplicity.

Some good neural network SCAL parameter predictors for Rt, and RI were generated using different combinations of standard wireline logs in the training well A-02. The best predictors were produced using the dataset from the entire 478 ft cored interval of the training well and all 7 available wireline logs. Predictors trained on data at 1.0 ft depth spacing appeared to be better in the training well. However, the prediction of resistivity parameters in an adjacent well and a further test well in a different oil field gave slightly better results in general for predictors trained on data at 0.5ft depth spacing rather than at 1.0 ft depth spacing.
Interactions Between Mud Acid and Sand Proppants
Authors: Assem A. I. , Nasr-El-Din H. A.
Published: September 2015

Proppants are required in hydraulic fracturing operations in the oil and gas industry. They consist of solid particles with specific strengths and are used to keep the rock fractures open in order to increase well production. They can be naturally occurring sand grains or artificial ceramic materials. Studying the acid resistance of proppants is important. Acids are needed to remove the scale and clays that affect the fracture conductivity.

This study investigated the different factors affecting the interactions between mud acid and sand proppants. Several experiments were conducted using the aging cell with mud acid (3 wt% HF, 12 wt% HCl) up to 300°F. The effects of temperature, soaking time, and static and dynamic conditions were examined. The supernatant of solubility tests was analyzed to measure total silicon concentrations using ICP-ES. The proppant was sieved before and after the experiments. Following that, the residual solids were dried and analyzed using a scanning electron microscope (SEM).

The results showed that sand proppant is soluble in regular mud acid, nearly 10 wt% dissolved in some cases. The amount of proppant dissolved increased with temperature, soaking time, concentration, and dynamic conditions. The fines generated and the changes in grain size distribution are detrimental to the proppant conductivity.

This work will help to achieve a better acid treatment design when sand proppant is used.
Development of Innovative Formulations to Mitigate Differential Delayed Cement Setting in Long Deep Liners in the Red Sea: Lab Study and Field Application
Authors: Al-Yami Abdullah S. , Jennings Scott S.
Published: September 2015

When cementing liners, the cement must develop compressive strength at the top of the liner before drilling is resumed. Sometimes at high temperature wells, it can take us up to 2 days just waiting for compressive strength development at top of liner conditions. This problem is common when cementing long liners in high temperature wells.

An earlier study done by Yami et al. (2007) showed the development of two new retarded systems. The first system is used for non-latex cements for wells that do not show indications of fluid flow. The second cement system includes latex and is recommended for liners with potential for fluid flow. The new retarder systems were effectively applied in a well in Red Sea. This paper discusses the non-latex system field application and summarizes lessons learned.

The field application was done by using sodium salt and alicyclic acid with aminated aromatic polymer in combination with sodium salt of organic acid and inorganic salt and aromatic polymer derivatives to cover differential temperature of more than 100 °F.
Laser influence to biosystems
Authors: Jevtic Sanja , Sreckovic Milesa , Pelemis Svetlana , Konstantinovic Ljubica , Jovanic Predrag , Petrovic Lazar , Dukic Milan
Published: September 2015

In this paper a continous (cw) lasers in visible region were applied in order
to study the influence of quantum generator to certain plants. The aim of
such projects is to analyse biostimulation processes of living organizms
which are linked to defined laser power density thresholds (exposition
doses). The results of irradiation of corn and wheat seeds using He-Ne laser
in the cw regime of 632.8nm, 50mW are presented and compared to results for
other laser types. The dry and wet plant seeds were irradiated in defined
time intervals and the germination period plant was monitored by days.
Morphological data (stalk thickness, height, cob lenght) for chosen plants
were monitored. From the recorded data, for the whole vegetative period, we
performed appropriate statistical data processing. One part of experiments
were the measurements of coefficient of reflection in visible range.
Correlation estimations were calculated and discussed for our results. Main
conclusion was that there were a significant increments in plant's height and
also a cob lenght elongation for corn.
Novel use of BiOCl as an efficient and selective reagent for cleavage of 2,4-dinitrophenylhydrazones to carbonyl compounds
Authors: Manesh Abbas , Azarin Khadijeh
Published: September 2015

A novel use of bismuth oxychloride (BiOCl) as an efficient and selective
oxidative catalyst for the clean cleavage of 2,4-dinitrophenyl-hydrazones
under mild conditions is reported. The reactions proceed very smoothly, and
the yields are good to excellent. Over oxidation of aldehydes to carboxylic
acid and the formation of by-products were not observed. The catalyst could
be recovered and reused for at least four reaction cycles without
considerable loss of reactivity.
"It happened, what’s the problem?" and "A guide through the problem": A model for consideration of ecological issues in chemistry education
Authors: Korolija Jasminka , Rajic Snezana , Tosic Milena , Mandic Ljuba
Published: September 2015

In order to improve the ability for application of knowledge of chemistry
(acquired in the existing educational system) in real life the Model for
Consideration of Ecological Issues was developed and applied in high school.
The Model consists of the continuous text (?It Happened, What?s the
Problem??) and the test with non-continuous text (?A Guide Through the
Problem?), which are prepared for consideration of the problem of
eutrophication. All results obtained (average achievement of 70.9?14.3 %)
showed that the application of the Model enabled: understanding of an
ecological problem based on scientific representations of the term
eutrophication given in the continuous text, realization that the pollution
of our environment may be directly related to modern life, application of
acquired knowledge of chemistry to observe and understand the cause and
effect of eutrophication in our environment, to draw a scientific conclusion,
and understanding the importance of science and technology discoveries for
solving ecological problems. In addition, Model contributed to the
development of student?s environmental literacy (ecological knowledge and
cognitive skills), ability to think critically, and provided possibilities
for classroom knowledge to become applicable in real life.