bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced History Matching Techniques Reviewed
Authors: Rwechungura R. , Dadashpour M. , Kleppe J. 
Published: September 2011

Abstract
The process of conditioning the geological or the static model to production data is typically known as history matching (HM). The economic viability of a petroleum recovery project is greatly influenced by the reservoir production performance under the current and future operating conditions. Therefore evaluation of the past and present reservoir performance and forecast of its future are essential in reservoir management process. At this point history matching plays a very important role in model updating and hence optimum forecasting, researchers are looking for new techniques, methods and algorithms to improve it.
This paper therefore reviews HM and its advancements to date including time-lapse seismic data integration. The paper covers manual and automatic HM, minimization algorithms including gradient and non gradient methods. It reviews the advantages and disadvantages of using one method over the other. Gradient methods covered include conjugate gradient, steepest descent, Gauss-Newton and Quasi-Newton. Non-gradient methods covered includes evolutionary strategies, genetic algorithm and Kalman filter (ensemble Kalman filter).It also addresses re-parameterization techniques including principal component analysis (PCA) and discrete cosine transforms (DCT). The methods are evaluated using a data set based on data from the Norne Field in the Norwegian Sea provided by Statoil and its partners to the Center of Integrated in Petroleum Industry (IO Center) at the Norwegian University of Science and Technology (NTNU).
Novel Drilling Technology Delivers a Step Change in Challenging Deepwater Operations
Authors: Clausen Jeff , Rebellon Jorge , Blanc Joe , Barton Steve 
Published: September 2011

Abstract
Jar technology has been around in the oil industry for several decades and its basic principles have remained primarily the same. As the oil industry moves forward in the exploration and development of unconventional hydrocarbon reserves, the demand for tougher, more reliable, and safer tools is more critical. Deeper wells and more complex well geometries are pushing the drilling envelopes, requiring tools to be engineered not only to withstand higher stresses downhole, but also to provide higher levels of safety on the rig floor. Through the engineering of simple but ingenious features, this paper describes how jar technology has been taken to a higher level.
A jar has been designed acknowledging the most important features required in the current demanding drilling scenarios. The industry is not only looking for safer and more reliable tools, but also tools that will provide higher firing loads to increase the levels of success of freeing a drill string during a stuck pipe incident. The loads delivered during the first hours of a stuck pipe event can significantly improve the chances of retrieving the drill string safely to surface.
The design features employed in this new technology maintain the same operating procedures of standard designs, but have increased the torque, tensile, and pressure ratings of the tool. In addition, current technology can suffer damage from excessive internal pressure build up when the over-pull rating of the tools are exceeded; particularly in deepwater applications where heave can be a contributing factor. A device has been engineered to protect the tool if such a condition is reached. The new jar also features a modular safety mechanism that will eradicate the use of the traditional safety collars eliminating the potential hazards of dropping objects on the rig floor.
This paper will provide an overview of the innovative technology, plus review the initial field trials. Testing and field trials will demonstrate how this technology is a true step change, matching the growing demands of the drilling industry.
Novel Borehole System for Reservoir Monitoring Using Transient Electromagnetics
Authors: Dutta Sushant M. , Reiderman Arcady , Schoonover Larry G. , Rabinovich Michael B. 
Published: September 2011

Abstract
In this paper, we describe a novel transient electromagnetic borehole technology for reservoir monitoring that has important advantages over existing borehole electromagnetic methods. This work is based on computer simulation of a waterflooded reservoir model that demonstrates the efficacy of this technique for reservoir monitoring.
Conventional and enhanced oil recovery (EOR) processes such as waterflooding, steam flooding, and chemical flooding cause key changes in reservoir fluid composition over time. The proposed transient electromagnetic borehole technology can be used for fluid front monitoring and to detect bypassed pay in reservoirs.
Existing cross-well borehole electromagnetic technology has shown potential for detecting changes in the reservoir over time by measuring resistivity contrasts. However, it has limitations; most notable being that the measurement is limited to the region between a pair of wells. We show that transient measurements have a distinct advantage over traditional continuous-wave measurements in that different segments of the transient signal can be mapped to different regions of the formation. Furthermore, the measured transient signal has no interference from the transmitter because the transmitter is silent when the formation signal is acquired. This technology eliminates the need for using two separate wells simultaneously, and it has better spatial resolution for the region close to the well. We present several 3-dimensional transient simulation results for a single-well triaxial transmitter-receiver system in a hypothetical waterflooded reservoir. Some of the measured signals demonstrate azimuthal and radial sensitivity to a water front 1,000 ft away.
This paper describes transient electromagnetic technology for a single-well borehole reservoir monitoring system that can be implemented with permanent sensors, while cross-well technology needs a multi-frequency multi-spacing transmitter-receiver system along with wireline logging equipment for multiple wells. The 3-dimensional transient electromagnetic computer simulations performed for this work are also an important addition to the knowledgebase of the industry.
Successful Application of Novel Fiber Laden Self-Diverting Acid System during Fracturing Operations of Naturally Fractured Carbonates in Saudi Arabia
Authors: Jauregui Jairo Leal , Malik Ataur R. , Solares J. Ricardo , Garcia Walter Nunez , Bukovac Tomislav , Sinosic Brian , Gürmen M. Nihat 
Published: September 2011

Abstract
Acid fracturing treatment performance is largely determined by the achieved effective etched fracture length. Evolution of fracture length during such treatments leads to progressively increasing the acid leakoff rate up to a point when the fracture stops extending. Zonal coverage and fluid loss control in naturally fractured carbonate reservoirs with high permeability contrast are the key challenges during acid fracture treatment.
Nonreactive and reactive polymer based fracturing fluids and diverters were historically accepted as systems that could efficiently control fluid leakoff. The performance of such fluids relies on wall building fluid loss additives, such as polymers. Their deposition on the fracture face forms filter cake that decreases fluid leakoff into the formation. Filter cake on the etched fracture wall could cause skin. Nondegradable particulate fluid loss additives used in naturally fractured reservoirs can be a good leakoff control tool; however, particulates could permanently shut natural fractures off and obliterate their production contributions. Finding the right balance between induced fracture damage and conductivity is a challenge, and avoiding this damage by using nondamaging fluid with major fluid leakoff control properties is the logical problem solution.
A novel fiber laden polymer-free self-diverting acid system was introduced in Saudi Aramco as an acid fracturing diverter to control fluid leakoff, and enhance the diversion process by combining the aspects of both particulate and viscosity based diversion techniques. The fluid system has a distinct advantage in that it does not contribute to formation damage because the viscoelastic surfactant will breakdown upon contact with hydrocarbons, and the fiber will degrade with time and temperature.
More than 25 acid fracture treatments using the novel acid system have been successfully implemented in gas bearing carbonate reservoirs in Saudi Arabia. Unlike the approach used in acid fracture treatments using conventional fluid systems, the degree of diversion was dynamically adjusted to maintain the treating pressure above the fracturing pressure throughout the entire period in these treatments. The bottom-hole pressure (BHP) measurement confirmed superior fluid leakoff control leading to an outstanding diversion performance with excellent gas production increments.
This paper provides details about treatment design, field implementation, and post-stimulation performance for two out of the more than 25 wells treated using this novel acid system.
Successful Offshore Deployment of the First Bottom Discharge ESP in Saudi Aramco
Authors: Shinaiber Fahad , Aborshaid AbdulHameed , Ghamdi AbdulRahman , Jokhio Sarfraz , Dhufairi Mubarak , Mofty Rayyan 
Published: September 2011

Abstract
Presented in this paper is the success story of the offshore deployment of a Bottom Discharge Electrical Submersible Pump (BD ESP), the first of its kind in Saudi Aramco. Based on an immediate need for pressure support at low cost, this pump was selected to provide the required injection volume and pressure for a water injection system using non-potable water (NPW). Water from a shallow depth (4,500 ft) was injected into an oil zone located below (7,400 ft), with no water at the surface, eliminating any need for treatment at the water injection plant.
The concept of using bottom discharge was considered as part of the ongoing efforts to evaluate different completion strategies for local and independent injection. Typically, a centralized water injection plant and pipeline network stretched over long distances is common practice within Saudi Aramco. These efforts were driven by the business need of a particular field to provide sufficient water injection to the producing reservoirs, with the consideration of low capital investment, and a short implementation time frame. Water conservation efforts require the Company to use either treated seawater or NPW (water so non-potable that it would be more expensive to attempt to treat it than use treated seawater).
Well X, an existing offshore completion suitably located close to oil-water contact (OWC) of the Arab-D reservoir and within the perimeter of the aquifer (TDS = 24,700 ppm), was selected for this application. These factors made the well an excellent candidate to test the BD ESP completion and to provide 8–12 thousand barrels per day (MBD) of water injection to support the Arab-D reservoir. The aquifer was perforated and the BD ESP completion was deployed successfully in tandem with a satellite communication surveillance system, to validate injectivity, optimize pump performance, and gather reservoir data for further analysis.
Streamline Simulation of CO2 Storage in Saline Aquifers
Authors: Saadawi Omar H. , Pickup Gillian E. , Jin Min , Mackay Eric J 
Published: September 2011

Abstract
Injecting CO2 in deep saline aquifers is one of many feasible options for mitigating climate change in the medium term. It is important, though, to evaluate the risk involved. Numerical simulations of CO2 injection may be performed to assess the likely migration paths. However, since aquifers may be extensive and highly heterogeneous, the time taken for conventional finite-difference simulations may be prohibitive. In this study, we investigated the application of streamline simulations as a means for speeding up simulations of CO2 injection. The simulations were carried out using a model that was constructed to represent a "generic" heterogeneous deep saline aquifer, using the geometry of the Tay Aquifer near the Forties Field in the North Sea. The main advantage of streamline simulation is its ability to process high-resolution grids efficiently and, in recent years, there has been a widespread increase in the use of streamline simulation in modelling oil reservoirs.
The first part of this paper describes a sensitivity study on several streamline-specific parameters to examine their impact on the simulation of CO2 storage in saline aquifers. The differences between streamline and compositional models were then examined. The comparison between the streamline and compositional simulations was carried out for two different injection strategies, designated as follows:
Scenario 1 – Injection of supercritical CO2 Scenario 2 – Injection of CO2 saturated brine
The results of the sensitivity analysis on the streamline parameters and the comparisons between the streamline and compositional models were analysed and contrasted. In particular, we found that in Scenario 1, where gravity effects are important, there were significant differences between the streamline and conventional simulation results. The streamline simulation produced a more diffuse plume. However, in Scenario 2, where density of the injected fluid was similar to the resident fluid, the simulation results were similar.
Role of Formation Pressure and Sonic Measurements While Drilling in Pre-drill Well Design Validation and Syn-Drill Well Design Optimization: Case Studies from Deepwater India
Authors: Agrawal Vikas , Singh Rajesh Kumar , Singh Juli , Shaikh M. I. , Dotiwala Firoze 
Published: September 2011

Abstract
Deepwater exploration is a challenging and cost-intensive endeavor. Optimal well design is critical to both cost control and successful execution of the drilling plan in this difficult arena. Generally, offset well data is very sparse for deepwater wells; therefore, it is critical to have real-time measurements while drilling to enable comparison with the pre-drill design model, allowing deviations from the plan to be noted and acted upon. Such quick analyses while drilling allow for midcourse corrections in the well design that not only help to drill safely at minimal cost, but also to maximize exploration returns in the form of reserve accretion.
The case studies discussed in this paper are examples where formation pressure-while-drilling (FPWD) and sonic-while-drilling technologies have been leveraged to enable while-drilling validation of pre-drill design and midcourse corrections in the well design. Proactive decisions on well design modification, including mud weight program, were taken which resulted in achieving maximum drilling efficiency and optimal quality of data acquisition at minimum cost. The use of FPWD and sonic while drilling technologies resulted in major cost savings in addition to obtaining vital geological and petrophysical data in the formation free of invasion-induced damage, against both argillaceous and arenaceous intervals encountered while drilling the well. This allowed for integrated analysis with already available VSP data and other data while drilling and resulted in deciding upon optimal section TD in at least one instance.
Mobility Control for Gas Injection in Heterogeneous Carbonate Reservoirs: Comparison of Foams versus Polymers
Authors: Masalmeh Shehadeh K. , Wei Lingli , Blom C. P. 
Published: September 2011

Abstract
Gas injection is a proven enhanced oil recovery method, especially for light oil reservoirs. The primary objective of gas injection is to improve the displacement efficiency and reduce residual oil saturation below the values usually obtained in waterflooding. However, the macroscopic sweep efficiency of gas injection can be suboptimal, mainly due to channelling, viscous fingering and gravity segregation of the injected gas. The macroscopic sweep of gas injection is further reduced for highly heterogeneous reservoirs.
In this paper we examine the ability of both foam and polymer to provide mobility control to gas injection in a mixed-wet carbonate reservoir with high permeability contrast, i.e, high permeability zone on top of a low permeability zone. Under waterflood, there is an impediment for water to flow from the high permeable Upper zone to the Lower zone due to e.g., capillary pressure.
The paper presents two new emerging technologies for mobility control of gas injection, which results in improving vertical sweep efficiency of oil reservoirs, namely: 1-SIMGAP: Simultaneous injection of miscible gas in the low permeable Lower zone and a polymer solution in the high permeable Upper zone. A lateral pressure gradient is maintained in the Upper zone by the injected polymer, providing Lower zone gas confinement; and2-Foam: Simultaneous injection of surfactant solution in the Upper zone and gas in the Lower zone. As gas migrates to the Upper zone, foam will be created in-situ and reduces both gas and water mobility in the Upper zone. This leads to the containment of the gas in the Lower zone, thus improving vertical sweep of the reservoir.
The EOR processes are compared based on recovery factor, possibility of success, robustness to geological heterogeneity and operating conditions and stability at high temperature and salinity conditions. Simulation results show that the two EOR processes have the potential of recovering the oil that is by-passed by waterflood or conventional gas injection schemes. The SIMGAP process (polymer based) leads to higher recovery factor than the foam process. Experimental data supporting simulation work was also conducted as part of this study.
Innovative Method to Control Acid Placement during the Stimulation of Wells with High Water Cut
Authors: Harbi Mesaad , Said Rifat , Arnaout Ibrahim , Haldar Surajit , Al-Subaie Fehead , Jenkins Christopher , Burov Anton , Kharrat Wassim , Ahmed Danish 
Published: September 2011

Abstract
Water production is a serious challenge when stimulating wells in mature reservoirs. Production results after acidizing sometimes reveal a higher water cut; in some cases this change is significant enough that the well is no longer able to flow unassisted. A typical acid stimulation in the field follows a predetermined pumping schedule, where diverter is squeezed into the high water cut interval prior to injecting acid into oil zones. The diverter volume is based on a rule of thumb and the acid is pumped after assuming that the diverter is efficiently sealing the high water cut zone. Several coiled tubing (CT) matrix stimulation jobs have yielded production results of 100% water cut.
Prior to stimulation (a period of months or years), diagnostic logs were conducted to identify water producing intervals. Although, in some cases, the post-stimulation water cut may be as high as or higher than the water cut prior to the stimulation, suggesting that the diverter volume was not enough to seal the water zone. An innovative method is needed to confirm the isolation of high water cut zones before pumping acid, which would lead to increased oil production and reduce the risk of unintentionally stimulating water producing zones.
This paper shares a case history of a cased and perforated vertical oil well from a field in which the operator was able to reduce the risk of acidizing a high water cut interval through the innovative use of a fiber optic enabled coiled tubing (FOECT) string and a pressure-temperature casing collar locator real-time downhole measurement tool.
The distributed temperature surveys (DTSs) recorded with the fiber optic cable were used as an innovative method to identify the water producing zone. This method correlated with the water producing interval identified by a wireline log run some period prior to the CT job.
DTS allows the assessment of diverter efficiency and the tracking of fluids placement. In this case study, acid was confirmed to have been squeezed only in the upper oil zone. As a result, the well production increased significantly without any increase in the water cut.
Effective Utilization of Variable Speed Drive with Electrical Submersible Pump's Boost Oil Production in a Remote Desert Field: Case Study
Authors: Al-Dossary R. S. , Al-Khuzayem R. A. , Al-Hajri M. A. 
Published: September 2011

Abstract
This paper presents a comprehensive review of a successfully employed methodology used for utilizing variable speed drive (VSD) with electrical submersible pumps (ESPs) to boost the oil production in a remote desert field in Saudi Arabia. The successful employed methodology was done through a structured test program for VSD frequency jackup. The program was designed to overcome the back pressure in the trunk line connecting this field and others to a Central Processing Facility where the downstream pressure of the wells are fluctuating within 60 psi with a maximum back pressure of 865 psi. The ESP frequency on the producers in this field was jacked up to a frequency measured below the maximum allowable operating pressure (MAOP) of the trunk line. The maximum frequency was adjusted through recording the deadhead pressure (DHP) of the ESP at different frequencies and selecting a new running frequency, which is the frequency recorded at the closest pressure below the MAOP of the trunk line. This test was done to boost the production from each producer while maintaining integrity of the trunk line. The production gain indicates that increasing the ESP frequency via the VSD is a very valuable tool.
This test was done on 15 producers equipped with intelligent field gadgets in which the data is transmitted to the production engineer's desktop. Every producer is equipped with an ESP unit with a sensor and VSD, in addition to a multiphase flow meter (MPFM) unit for rate measurements.
The VSD, which is designed specifically for use with the ESP, has been available for several years. The utilization of the VSD as an effective tool to increase the production from the ESP is very well documented in the oil industry. The ability to vary the operating speed of the ESP through the VSD greatly expands the production range of the ESP. In this paper, the methodology and the structured test program implemented in the (R) field during the frequency jack-up campaign utilizing the VSD on the producers will be discussed, in which the post-test and pretest results will be shared and examined. Although, the long-term effects of operating the ESP pumps on high frequency and high amps for extensive periods of time will not be covered in this case study.
Modeling the Oil Bank Formation during Steam Flood
Authors: Alajmi Abdullah F. 
Published: September 2011

Abstract
The development of unconventional oil resources is becoming important factor to meet the increase of world oil demand. One of these unconventional resources is heavy oil deposits. Producing this high viscosity oil is complex and challenging. These resources usually require thermal recovery techniques in which heat is introduced into the reservoir to lower the oil viscosity. Steam flood is a popular thermal recovery method. Understanding the mechanism of steam injection and heat utilization improves the efficiency of heavy oil recovery. In this work, steam flood is applied to Middle Eastern heavy reservoir, and the advancement of steam zone and formation of oil bank ahead of it are investigated and modeled. First, experimental work was done to conduct the steam injection to unconsolidated core sample saturated with heavy oil. X-ray computed tomography (CT) was used during the experiment. The experimental data and X-ray CT measurements were used as input data to the numerical simulation to further understand the development and formation of the oil bank as steam is injected. The results show that the size of oil bank and its location from inlet side depend on several parameters such as initial oil viscosity and steam quality. This study provides valuable information on the development of oil bank which help in quantifying the oil saturation distribution during steam flood.