bluuebunny/crossref_metadata_2025_split huggingface dataset:
Applying Flow Zone Index Approach and Artificial Neural Networks Modeling Technique for Characterizing a Heterogeneous Carbonate Reservoir Using Dynamic Data: Case Study of an Iranian Reservoir
Authors: Shahvar Mohammad Bagher , Kharrat Riyaz , Matin Mehdi 
Published: July 2010

Abstract
Although static characterization of reservoirs is an inevitable part of any reservoir studies, the most robust models of the reservoirs can be obtained through integrating static and dynamic data. The following study which is done in a heterogeneous carbonate reservoir utilizes the capillary pressure and relative permeability data to verify the task of static rock typing and investigate the role of hydraulic units in capillary pressure and relative permeability modeling. For this purpose, at first, various rock typing techniques are applied to the field data to seek the best method which has the most consistency with capillary pressure curves. Using Desouky method which is based on hydraulic unit concept, Leverett J-function was then correlated with the normalized water saturation for each rock type to normalize and estimate capillary pressure curves. An excellent agreement exists between the measured data and calculated ones approving the applicability of Desouky method in heterogeneous carbonate reservoirs. Then, using porosity, permeability, wetting phase saturation and some functional links as input data, artificial neural networks (ANN) and specifically the back propagation feed forward neural network is applied as a new approach to predict relative permeability. However, instead of constructing the model for the entire depth of the well, discrete models are developed for each hydraulic unit individually. This idea is generated from the fact that each hydraulic unit has its own set of relative permeability curves and each set differs from one unit to another so the task of separating the models can reduce the discrepancies of the data and thus providing the more accurate synthetic models for predicting relative permeability. Results obtained from this model are compared with those of applying multiple regressions and also ANN method for the entire depth of the well. This comparison showed that the new approach introduced in this study can enhance relative permeability prediction considerably.
A New Precipitation Squeeze Alternative for Treating Harsh Barium Sulphate Scaling in a Highly Naturally Fractured North Sea Carbonate Reservoir
Authors: Todd M. J. , Lamont G. , Thornton A. R. , Gibb A. K. , Langvik M. , Sjursaether K. 
Published: July 2010

Abstract
Harsh barium sulphate scaling downhole presents a significant squeeze treatment challenge, particularly with providing and then maintaining scale inhibitor residual concentration for extended period at and above the high MIC demand. The control situation worsens considerably when faced with such a scenario in a high temperature, naturally fractured carbonate well. Conventional dispersive type squeezes have found favour here, however their placement and subsequent rapid return at high concentration can result in low squeeze lifetime, mainly due to poor retention of the inhibitor type. The paper details a solution to the inhibitor retention and high MIC demand challenges via development of a novel precipitation squeeze formulation which utilises the dispersive type scale inhibitor as its primary active.
The phase-separating ‘precipitation squeeze’ inhibitor formulation is designed to be deployed via conventional bullheaded squeeze into a high temperature, naturally fractured carbonate well environment. The material will thermally activate causing phase separation and enhanced retention of the inhibitor as its calcium salt. Since the active inhibitor is highly tolerant to calcium, it will return into solution with greater facility than conventional precipitation squeeze analogues, leading to elevated levels of scale inhibitor in solution for extended periods compared to standard chemistries in the same carbonate environment.
Simulated carbonate field coreflood tests indicated a 3-4 time squeeze lifetime extension was achievable using this technology, and formation damage assessments indicate no identifiable damage to the core material or fluid throughput. The material is now developed for bulk manufacture and is now in the field awaiting first pilot squeeze deployment at the time of writing this abstract.
This novel alternative squeeze treatment shows significant increase in achievable squeeze lifetime compared to existing scale inhibitor chemistries for squeeze deployment in harsh barium sulphate scaling carbonate field deployments. Benefits are logistical, environmental and economic when deploying this technology.
First Matrix Stimulation of Producer Wells in Sudan Delivers Outstanding Results
Authors: Shaheen Tarek , Ghazi Hassen Ben , Al Abdalla Fahmi , Izat Ali M. 
Published: July 2010

Abstract
After producing for more than nine (9) years, many wells in Sudan are suffering from lower production rate and increase in the skin value due to formation (Sand Stone) damage. Only re-perforation technique was used to mitigate formation damage problems; however, the results were not satisfactory.
Considered the first time in the history of oil production in Sudan, Some of the idle producer wells in Greater Nile Petroleum Operating Company (GNPOC) operations fields were selected to treat their formation damage problems and to start the first Matrix Stimulation Engineering treatment.
The results were outstanding where the oil production rate went up in the well TS-21 from 23 bopd to 1360 bopd. The well is still sustaining the high production rate after one year of treatment. The great success encouraged the implementation of the Matrix Stimulation treatment in different fields like Simber West where the results of the well SW-1 reached from 10 bopd to 900 bopd.
This paper discusses the methods used in identifying the Matrix Stimulation candidates and the innovative solution including the lab tests and the chemical work done in order to determine the best fit for purpose chemical treatment to bring the wells back to production and optimize the production trend in the field of Toma South and Simber West. It describes the Matrix Stimulation of the well TomaSouth-21 as an example. Furthermore, it describes the entire lesson learnt from the execution and operation phase
Last but not least, it shares the outstanding results and the way forward for the Matrix Stimulation business in Sudan. It gives a good reference and database for the stimulation treatment in Sudan since this paper is the first one to be written regarding Matrix Stimulation treatment in Sudan.
Successful Applications of Expandable Sand Screen in Persian Oil Fields, Part 1
Authors: Salehi-Moorkani Reza , Abbas Safian Gholam , Mirzaei-Paiaman Abouzar 
Published: July 2010

Abstract
In some Iranian oil fields hydrocarbon recovery is mainly from sandstone reservoirs and sand production is a major problem in these fields. Main reason of sand production in these reservoirs is due to unconsolidated sandstone layers. The common method to decrease this problem is achieved by installing mechanical sand control systems. Previously, some techniques of sand control have been used in Iranian oil fields, such as gravel packing, slotted liner and chemical consolidation by resin. The results which have been obtained through these methods are not remarkably good enough in some cases.
Expandable sand screen (ESS) is a new technique in sand control that can result in lower skin and consequently improves reservoir inflow performance. Field tests in various conditions have shown very satisfactory results in both open and cased hole applications. This paper will provide a brief overview of ESS and its advantages and will explains some of the concerns deal with ESS well completion. It provides details of well production results before and after installation of ESS. It also suggests that the use of ESS as an alternative to conventional sand control methods in Iran oil fields is preferable specially in cased hole completed wells.
Intelligent Wells: Horizontal Well Simulation for Thin Oil Rims Abundant in the Niger-Delta - A Case Study
Authors: Mogbo Obuekwe 
Published: July 2010

Abstract
A simulation case study is described which illustrates the application of an intelligent horizontal well to an isolated reservoir with a thin oil rim in the Niger Delta.
Simulation of the intelligent well ability to simultaneously monitor and respond to reservoir conditions in two or more zones has proved to be a challenge for the performance forecasting of such wells. Recently, in the Niger Delta, Intelligent wells have began to be routinely used both for their economic benefit and their advantages in accessing remote and difficult locations for work-over during hydrocarbon exploitation. Furthermore, intelligent horizontal wells are finding utilization because remote thin oil rims are abundant in the Niger Delta.
The paper begins by a brief discussion of the intelligent well simulation methodology: Several fitting chokes (ICVs) are modelled along the length of the well in a commercially available simulator. This means that production from different segments could be controlled individually by the ICV's. The effect of the smart completion is recognised and analysed: constraints of water and gas production rates per segments are applied to shut in well segments automatically as water and gas constraints are reached. Furthermore, typical economic analysis for intelligent well justification is done. The results show that intelligent horizontal well completion is justified for this field.
Parametric Study of Condensate Buildup in a Naturally Fractured Gas Condensate Reservoir
Authors: Ebrahimi M. 
Published: July 2010

Abstract
The main difficulty usually encountered in gas-condensate reservoirs is the loss of valuable condensed liquid in the reservoir due to capillary forces, a phenomenon called condensate blockage. The presence of condensates when coupled with the complexity of fluid flow in fractured reservoirs can increasingly obscure the expected performance of such reservoirs. A thorough understanding of the factors leading to condensate buildup in fractured reservoirs is crucial for deciding a proper strategy to exploit such reservoirs. In this paper, a compositional model is used to predict and physically justify the single-well performance of a naturally fractured gas-condensate reservoir having different reservoir properties and production schemes.
The current study reveals the important role of capillary pressure in trapping condensates, especially in highly fractured reservoirs where the effect of gravity drainage is minimized. Higher matrix block sizes can reduce the amount of trapped liquid. However, high critical condensate saturation can dampen the effect to some extent. Pore size uniformity is another important factor that causes less condensate buildup due to less capillary pressure. Higher production rates result in earlier condensate dropout peak. The peak is lower for higher rates, a phenomenon attributed to velocity stripping. Furthermore, the effect of gas and liquid diffusion is the most crucial in tighter matrices and can significantly reduce the trapped condensates.
DC Electric Standalone Choke
Authors: Abicht Daniel 
Published: July 2010

Abstract
With the successful installation, commissioning, and operation of the first All Electric System in the Dutch Sector of the North Sea, the All-Electric Subsea Controls Systems technology continues to prove its advantages. As the 2-off subsea trees are currently gaining field experience, proving their defined targets such as e.g. improved reliability & availability and real time feedback, spin-off technology already has been developed.
Considering a customer survey and subsequent market analysis the need for an electric high precision choke being controlled from a standard electro-hydraulic multiplexed Subsea Control Module (SCM) clearly has been identified. A mature development initiative planting the design on the successfully field proven CameronDC™ Choke was initiated.
The DC electric Standalone Choke can be controlled from an electro-hydraulic multiplexed SCM utilizing minimum power consumption along with a standardized CANopen interface enabling high precision choke control, continuous position feedback, and improved operatability. In combination with dedicated Choke Control Software flow from multiple wells for enhanced recovery can be optimized.
Along with the description of the experience gained during the development this paper will discuss the inherent advantages of the DC electric Standalone Choke applied to subsea production systems.
The Occurrence of Unconventional Natural Gas Reservoirs Offshore Trinidad
Authors: Figueira B. , De Silva J. M. , DeLandro-Clarke W-L. , Bertrand W. 
Published: July 2010

Abstract
The island of Trinidad, situated at the easternmost extremity of the Eastern Venezuela Basin, is a known producer of conventional hydrocarbons, oil in previous years and natural gas at present. However, not much work has been done to identify, and more importantly, quantify the unconventional natural gas hydrate resource present in the Trinidad area. This paper presents a methodology for the identification of natural gas hydrate in Trinidad and the initial findings of this methodology using primarily three-dimensional (3D) seismic data from eastern offshore. The dataset covered an area of approximately 1788.6 km2 of transition zone between the continental shelf and slope in the Columbus Basin.
Analysis of the data shows the presence of several positive indicators which suggest that natural gas hydrate is present in the oceanic sediments. Bottom simulating reflectors (BSRs) were observed on the seismic data and the areal extent of these BSRs was determined to be 516.8 km2 or approximately 29% of the area of the mapped seafloor. Several mud volcanoes were also observed on the seismic volume.
Identifying and Quantifying Thin-Bedded Pay (Part A): Log Characteristics and Reservoir Quality
Authors: Henderson K. , Rose H. , Winter R. 
Published: July 2010

Abstract
Thinly bedded reservoirs are common throughout the Columbus Basin, but have traditionally been overlooked as productive targets. The presence of interbedded shales suppresses resistivity values within the thin sand beds (&lt;2 feet thick), resulting in low-resistivity log signatures that do not meet conventional pay cut-offs. Core data and advanced high-resolution log analysis are required to accurately evaluate reservoir quality. In the absence of such data, thin bedded pay can still be identified on conventional logs as low resistivity intervals and a modified petrophysics workflow can be used to estimate gas-in-place.
An example is taken from a recently drilled well where 180 feet of conventional core was acquired together with an advanced logging suite over a thinly bedded interval. The resulting petrophysical analysis indicates lower water saturation than predicted by conventional logs, which is independently supported by wellsite plug measurement. Core data also demonstrates that the porosity and permeability distributions in the cleaner, thin sand beds show similar ranges to conventional "thickly bedded" sands, irrespective of bed thickness. Porosity and permeability decrease in the more heterolithic zones (with increasing silt content) as would be expected.
These results endorse the concept that reservoir quality of thin sands is comparable to that of thicker sands, although this may not be evident from conventional log analysis. As a result, a well-by-well screening was carried out for a number of fields in the Columbus Basin to identify and classify potential thin bedded intervals based on typical log signatures. The reservoir properties of these intervals can then be evaluated using a modified petrophysics approach based on calibration to the core and advanced logging technology. This workflow has proved to be an important tool for the identification of thin bedded intervals, highlighting opportunities for targeted surveillance and providing an inventory of potential targets for future access.
Identifying and Quantifying Thin-Bedded Pay, Part B: The Use of Dynamic Data to Evaluate Productivity Potential in Gas Reservoirs
Authors: Baillie K. , James-Romano J. 
Published: July 2010

Abstract
Intervals of thinly bedded sands have been identified above or below conventional ‘thickly bedded’ gas reservoirs currently under production. The level of contribution to flow from thin bedded pay however is uncertain and difficult to distinguish from that of the thick, conventional pay intervals. Production data solely from these intervals is extremely limited, so confirming production and ultimate recovery from these resources is challenging.
Thinly bedded intervals have historically not been targeted for completion, but may still be contributing to gas rates over a long term production time scale. Producing reservoirs in the bpTT portfolio may already provide evidence for the potential productivity of thin bed pay. Static pressure data from several wells in reservoirs with thin bed pay above or below completed conventional pay intervals have suggested pressure support from a lower rate source when wells are shut in for an extended period of time. Pressure transient analyses in other wells have interpreted heterogeneities in reservoirs where traditionally only conventional thick bedded intervals were considered.
In lieu of direct evidence of production such as Production Logs and costly dedicated Thin Bedded Pay well tests, existing data has been used to confirm contribution to flow from thin bed pay and add to recoverable volumes. Formation pressures for a reservoir in the Amherstia field were used to prove depletion and increase the recoverable volumes from time bed pay in 2009. This interval was consequently identified as a future recompletion opportunity. Thin bed pay intervals were also targeted and completed in two newly drilled wells in the Cashima field. Though still early in their production lives, these wells are already showing signs of contribution from thin bed pay. The Amherstia and Cashima success stories demonstrate the potential for thin bed pay as an important resource for the future of bpTT.
Ensemble Based Characterization and History Matching of Naturally Fractured Tight/Shale Gas Reservoirs
Authors: Ghods Parham , Zhang Dongxiao 
Published: July 2010

AbstractTight sand and shale gas reservoirs are becoming bigger players in natural gas supply system as easily developed gas resources become scarcer, natural gas prices go higher, and more efficient technologies become available to develop these hard-to-access reservoirs. Although these reservoirs are hard to develop, recent technologies such as better hydraulic fracturing are making them more productive.Production and development of these types of reservoirs depend heavily on the hydraulic fracturing and the existence of natural fractures in the formations. Since the permeability of the matrix is very low no commercially feasible gas production can be achieved without fracturing. Therefore, characterizing and understanding the fractures have become of great importance.We have proposed using a combination of methodologies for fracture characterization and simulation in tight gas reservoirs. Dual Porosity Dual Permeability modeling has been used for simulating fractured reservoirs. For a commercial simulator to be able to simulate the fluid flow in a reservoir, properties such as permeability and porosity should be known which are, however, not adequately measured. The most readily available measurements are indirect observations such as bottom-hole pressures and production rates. Using indirect measurements to constrain the model parameters requires solving an inverse problem. In this study, Ensemble Kalman Filter (EnKF) is used for the estimation purposes. EnKF is a Monte Carlo based, minimum mean square error (MMSE) estimation tool that generates multiple realizations based on the prior knowledge of the reservoir, in which the model performance is improved via sequential assimilation of the observations.Our proposed methodology is tested on several synthetic 2D reservoir models containing a number of fractures, some intersecting the wells. The results have proven the applicability and the advantage of this methodology. We have shown that EnKF can be used efficiently to characterize a fractured reservoir when the approximate orientation of the fractures is known which may be obtained from the stress-strain field data in the reservoir.
Implementation of PinPoint Fracturing Technique in the Western Egypt Desert
Authors: Mohsen Adel , Ali Mohamed Ahmed , Samiee Rady Abdel , Ibrahim Ehab , Taha Islam Mohamed , Hamdy Mostafa 
Published: July 2010

Abstract
In the western desert region of Egypt, previous propped multiple-fracture treatments were performed using conventional methods (i.e., perforate, frac, set mechanical/zone isolation, and repeat cycle). Although the resulting treatment efficiency was satisfactory, other methods were being considered to help reduce cost and improve production performance. Also, it was desired to decrease total operational time, which would further impact economics (rig time, production delay, etc).
In an attempt to improve production response, fracturing designs in the El Fadl field in the western desert went from a standard three-stage design up to as much as a six-stage design to more effectively stimulate the pay zones. A careful review of the field and operations suggested possible benefits from implementing the pinpoint method for hydraulic-fracturing treatments. It was, however, not a simple case of just applying a hydraulic-fracturing treatment to every potential zone, but required proper well screening, thorough log analysis, calculating and validating mechanical rock properties, and enhanced 3D fracture modeling to achieve a successful campaign.
A pinpoint method for stimulation was implemented to perform multistage jobs at reduced costs. As the stage count per well was increased, production response and economics were improved. Both treatment design and staging design with this fracturing technique continue to be further refined as performance and statistical analysis of previous design changes are completed.
This paper discusses a pinpoint method for frac treatment and the methodology applied on a recent well. Differences in job execution that will be discussed include: using a hydrajet perforating mechanism instead of conventional casing-gun perforation, time-consumption reduction, analysis of vertical-fracture coverage per potential zone, and cumulative production response from the different designs tested. This could serve as guidelines for other operators who might be facing similar challenges in the North Africa region and elsewhere.