bluuebunny/crossref_metadata_2025 huggingface dataset:
Enhancement of Oil Recovery through "Dump-flood" Water Injection Concept in Satellite Field
Authors: Shizawi Wafa , Subhi Hamed , Rashidi Ahmed , Dey Arunangshu , Salmi Fathiya , Aisary Mohammed
Published: September 2011

W-field is a small satellite field that started seeing some means of pressure depletion. Field development study recommended waterflood as the most effective option to arrest the reservoir pressure decline and enhance the oil production and recovery.

The size and the satellite location of the field could not economically justify a conventional water flood project. A "DumpFlood" concept was implemented where a single well is used as a source of water supply and inject domain. The well was perforated in the deeper water reservoir Z and on the injection target reservoir H. The well was completed by an advanced ESP that was designed to produce and inject in the same wellbore across the two set of perforations.

Surveillance program was put in place and implemented focusing on reservoir pressure monitoring in the surrounding wells, production metering and periodical surface flow of the dump flood to assess its productivity and injectivity. Downhole gauges were installed in the dumpflood well across the two units to monitor the reservoir pressure behaviour and the calibration of the injection rate.

The concept proved its success, an injection water rate of around 1200bpd was achieved in the target zone. Pressure response and some segneficant oil gain in the range of 40% was noticed in the w-feild. The concept is now under review for further implementations in the same field and the design is ongoing to apply the concept in other two fields in the area.

The dumpflood concept allowed an economical waterflood project to be applied in Z fields with the expectation of significant oil recovery to be achieved.
Enhanced Sustained Production from Successful Underbalanced Coiled Tubing Drilling in Saudi Arabian Deep Tight Gas Sandstone and Carbonate Formations
Authors: Al-Omair Ahmed , Al-Jamaan Hamza , Rahim Zillur , Al-Malki Bandar , Al-Kanaan Adnan
Published: September 2011

Gas encountered in deep carbonate (Khuff) and deep sandstone (Jauf and Unayzah) formations require significant planning and impelemntation of high-end technology for optimized exploitation. The conventional drilling methods for vertical, horizontal, and maximum reservoir contact (MRC) have been used extensively to produce the reserves. The need to avoid formation damage and minimize differential sticking has become important to maintain the well integrity and rates, particularly in reservoirs that are tight and encountering pressure depletion with time.

Underbalanced Coiled Tubing Drilling (UBCTD) technology is a breakthrough in developing mature and depleted reservoirs. With UBCTD, workover operations, such as drilling laterals in very thin reservoir sections and controlling their trajectories with flexibility to steer into net pay sections, are achieved with more accuracy. Also, the high operational costs with rig time, the need of inducing hydraulic fractures and drill-in mud invasion caused by conventional drilling are avoided. In addition, the technology plays a major role in eliminating pressure differential sticking while drilling across multilayered reservoirs that exhibit layering depletion. The technology was introduced after conducting a pilot project with six wells where post-UBCTD production performance were analyzed and exceeded expectations. In some cases, UBCTD provided as much as a threefold increase in initial well productivity and achieved a higher, long-term sustained rate compared to conventional workover operations conducted in similar reservoirs. Due to the ability to continuously monitor well performance during drilling and the higher flexibility of coiled tubing (CT) operations, changes in drilling direction and inclination could be easily made to maintain the drill bit in layers of interest and enhancing reservoir contact in the desired sections.

This paper presents two actual examples from carbonate and sandstone reservoirs where UBCTD has been successfully deployed. The post-workover pressure and production performances and comparison with results obtained from conventional drilling are presented to illustrate the improvement in gas rate. The paper also presents pressure transient tests conducted after workover operations indicating low or zero skin damage and high permeability-thickness (kh) as a result of effective minimization of wellbore damage from drill-in mud and achieving higher net-pay contact.
Geosteering Improvement With A Telemetry Model
Authors: Hartmann Andreas , Akimov Oleg , Fulda Christian , Morris Stephen
Published: September 2011

Introduction of new measurements constantly increases the amount of real-time data from logging-while-drilling (LWD) services. This is matched by telemetry technologies that provide data rates from bits to Mbits per seconds. During a deployment, the bandwidth is shared between several services requiring different data rates, leaving the user with the task to align telemetry technology and shared data rates to the application. High-volume services often allow for data compression. Lossless or near lossless compression provides best data quality but makes a service greedy for bandwidth. Lossy compression drastically reduces bandwidth usage, but may result in degraded data quality. Thus, planning the telemetry must be closely tied to the service objectives and expert advice is required.

We present a planning approach where we model the real-time data compression of an LWD high-resolution imaging tool that uses a flexible compression algorithm. This system allows lossy compression for telemetry rates as low as 1 bit/s, while at the same time can deliver memory data quality using high-speed telemetry technology. The compression rate determines the image resolution and must be adjusted to the detail required in the transmitted image. Using offset well data or simulated memory data, the expected real-time image is simulated and its level of detail quantified. For instance, the presence and appearance of fractures in real time can be forecasted. This enables us to optimize telemetry usage and define compression and drilling parameters for a successful deployment of the imaging service.

The paper will outline the methods and benchmark the technology using real-time data measured during field deployments. We will then use parameter variations to show how increasing net bandwidth improves the amount of detail in the images and how these are used for different levels of real-time data interpretation.
Cementing at High Pressure Zones in KSA "Discovering Mystery behind Pipe"
Authors: Al-Dossary Abdulla Faleh , Al-Majed Abdulaziz , Hossain M. Enamul , Rahman Muhammad Kalimur , Jennings Scott , Bargawi Riyadh
Published: September 2011

Cementing is one of the most important and crucial issues in the oil field, especially for high pressure and gas bearing formations. It is difficult to achieve a good zonal isolation in such formation types, where pressure is abnormal and formation fluid contains corrosive fluids and gases. A common problem associated with highly over-pressurized zones is cross-flow after cementing. Fluid flow from an over-pressured zone to a low-pressure, high-permeability zone can lead to deterioration of the existing production hardware. Work over operations that attempt to repair cement voids — including: perforation, squeezing and use of casing patches or scab liners — are not recommended, as they do not provide long-lasting results. In one onshore field in Saudi Arabia, there was a problem related to cementing at high pressure zones. Recently, communication between A (abnormally over-pressurized zone) and B (low-pressure zone) formations occurred due to long term sea water injection, and has resulted in production interruption in a few wells. This paper addresses the problem through investigating field practices, including: drilling, cementing, and completion. This study also reviews the field reports and cased hole logs. A three-month study was conducted to evaluate the effects of formation-A water on cement, where the cement was exposed to formation-A water under downhole conditions. The tests for permeability, mechanical properties TGA and EDXRF are presented, in addition to discussions of some of the preliminary findings.
Shallowest Horizontal Well Drilled in the Middle East: Challenges and Successes
Authors: Dutta Abhijit , Al Azmi Bader M. , Al Abri Hakim , Ali Musab
Published: September 2011

Major plans are underway to exploit the vast resources of heavy oil in very shallow regions of Kuwait. The horizontal well, an important tool for commercial exploitation, poses great challenges in shallow depths and requires high dogleg severity (DLS) through extremely loose formations while drilling with a conventional Kelly drive rig. This paper highlights the challenges encountered and the use of multi-tier planning and perfect execution that enabled the successful drilling and completion of the shallowest horizontal well ever drilled in Kuwait and the Middle East region in the first attempt. Two medium-radius, extremely shallow horizontal wells were successfully drilled using a conventional Kelly drive rig. The success of both wells introduces the application of horizontal well drilling in heavy oil reservoirs, which is expected to maximize production per well and reduce the large number of vertical wells planned, thereby reducing costs of the project.

Concerns were raised regarding the feasibility of drilling such a well with high DLS through grossly unconsolidated sands with a conventional rig to successfully lower all the casings. Meticulous planning, engineering analysis, proper tool selection, and development of drilling procedures were performed before undertaking the venture. The experience of drilling 75 similar vertical wells was extremely valuable while planning and completing the project.

Kuwait Oil Company (KOC) approached the project in a holistic manner. The drilling group prepared several plans and deliberated at length with asset and service partners to analyze and firm up the plan. The advantages and disadvantages of a conventional rig versus a slant rig or top drive rig were also analyzed. KOC ultimately used the cost-effective conventional rotary rig and were able to successfully drill both wells. The first well reached horizontal at a shallow TVD of 680 ft with a kick-off point at 96 ft and a 1,290-ft lateral completed with a liner through unconsolidated loose sand.
Advanced History Matching Techniques Reviewed
Authors: Rwechungura R. , Dadashpour M. , Kleppe J.
Published: September 2011

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

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

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

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

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

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

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

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

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

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

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.
Integrated History Matching Simulation Study of the First Miscible CO2-EOR Pilot in Abu Dhabi Heterogeneous Carbonate Oil Reservoir
Authors: Al Hajeri Salma , Ghedan Shawket , Al Basry Ali , Negahban Shahin
Published: September 2011

Carbon Dioxide (CO2) Enhanced Oil Recovery (EOR) process is most likely to be the future hydrocarbon recovery process in Abu Dhabi[1]. In November 2009, Abu Dhabi Company for Onshore Oil Operations (ADCO) has commissioned the first CO2-EOR pilot in the Middle East. The pilot project was implemented successfully on a fast track basis with a broad objective to test the concept of CO2 flooding in Abu Dhabi complex carbonate oil reservoirs.

The project comprises three wells, a single CO2 injection well, an observation well and a single oil producing well An intensive reservoir monitoring plan was implemented pre-and post- CO2 injection to evaluate the uncertainties related to the reservoir fluid and rock properties, CO2 injectivity, miscibility, and sweep efficiency.

Available reservoir static and dynamic data was employed to construct a fully compositional simulation model to history match the pilot performance based on remarkable field observations. Effort was made to ensure that all reservoir data were quality checked, re-interpreted and validated before being utilized in the simulation model.

Conventional history matching was conducted to match the model response to the pilot performance. This is complemented with Software Assisted History Matching to further quantify and assess the range of uncertainties for different reservoir parameters that would impact the quality of the history match. Sensitivity analysis was carried out to identify those parameters that have the most effect on the pilot performance.

This paper outlines the main findings for the first miscible CO2-EOR pilot in Abu Dhabi based on well calibrated compositional model considering the most critical reservoir uncertainties affecting the process.
Zeta Potential Investigation and Mathematical Modeling of Nanoparticles Deposited on the Rock Surface to Reduce Fine Migration
Authors: Ahmadi M. , Habibi A. , Pourafshry P. , Ayatollahi Sh.
Published: September 2011

Fine migration is a noticeable problem in petroleum production engineering. Plugging of throats in porous media occurs due to detachment of fine particles from sand surfaces. Hence the study of interactions between fines and pore surfaces and investigating the governing forces are important issues to describe the mechanism of fines release process. The main types of these forces are electric double layer repulsion and London-van der Waals attraction. It is possible to change these forces by the use of nanoparticles as surface coatings. Nanoparticles increase the effect of attraction forces in comparison with repulsion forces.

In this paper, we present new experiments and modeling to observe these properties of nanoparticles. For this purpose, the surface of pores was coated with different types of nanoparticles (MgO, Sio2, and Al2O3). Zeta potential test was used to examine changes in potential of the pore surfaces. Total interaction energy is then mathematically calculated to compare different states. Total interaction energy is a felicitous criterion which gives proper information about the effect of different nanoparticles on surface properties. Accordingly, the total interaction plots are found to be the suitable tool to select the best coating material.

10-μm-diameter silica spheres and glass beads packed cwere utilized as fines and porous medium, respectively. Measurements were performed in 1:1 electrolyte aqueous solution of 10−3 mM, and probe-plate separation distances varied from less than 1 nm to 50 nm. Magnitude of change in zeta potential for MgO nanoparticle is 45 mV. Our model demonstrated that the magnitude of the electric double layer repulsion in comparison with the London-van der Waals attraction between probe and plate surface was considerably diminished when MgO nanoparticle was used to coat the surface of plate which is in complete agreement with our experimental observation.
While Drilling Mobility and Distributed Temperature Profiles Applied to Matrix Stimulation of a Giant Carbonate Oil Field: A Case Study
Authors: Dhufairi M. A. , Orban N. , Ahmed D. , Ebrahim A. , Kalinin D. , Baez F.
Published: September 2011

This case study focuses on a Middle East giant carbonate oil field drilled with horizontal producers and water injection wells. In this particular field, formation pressure while drilling measurements are primarily used to characterize the mobility of the formation fluid, to ensure injectors are optimally placed in good injectivity intervals and producers in high productive zones. Acid stimulation is required to mitigate drilling induced reservoir damage. Owing to the length of the open hole sections and the high heterogeneity of the formation mobility, effective placement of acid is very challenging. Viscoelastic diverting acid is commonly used to assure good zonal coverage across each stimulation stage, but the length of the extended reach wells requires optimum diverter placement for cost effectiveness.

An innovative methodology using distributed temperature surveys (DTS) with fiber optic enabled coiled tubing was introduced to compare pre-treatment injectivity with the mobility profile acquired while drilling before formation damage has occurred. The predicted injectivity/productivity profile computed from mobility measurements is used to establish the fluid placement strategy during the pre-job planning stage to decide on the required amount of acid and diverter. During the matrix stimulation operation, the temperature profiles after an injectivity test are compared with the baseline DTS temperature and mobility profile to identify thief zones and intervals with drilling damage. The availability of this information at the well site during the acid treatment allows the selective placement of diverter fluid across the thief zones, verification of the effectiveness of the diversion, its distribution along the wellbore, and accurate spotting of acid across damaged zones.

By implementing this process, under stimulated intervals close to the heel section, which has longer exposure time to the drilling fluids, were identified. The current practice of pumping alternating stages of acid and diverter for certain lengths of wellbore segment has been revised and a new optimized approach was introduced. The new methodology has been applied to several wells and has allowed a better use of available treatment fluids to obtain more even injectivity/productivity profiles and maximize stimulation effectiveness.
Lessons Learned from the First Miscible CO2-EOR Pilot Project in Heterogeneous Carbonate Oil Reservoir in Abu Dhabi, UAE
Authors: Al Basry A. , Al Hajeri S. , Saadawi H. , Al Aryani F. , Obeidi A. , Negahban S. , Al Yafei G.
Published: September 2011

In 2009, ADCO implemented the first ever CO2 EOR pilot in the Middle. The pilot project is part of the Company overall strategy evaluate the feasibility of CO2 injection as an EOR process and in order to address key technical and business uncertainties as well as the risks associated with CO2 injection The pilot project includes three wells, a CO2 injection well, an observation well and an oil producing well. The pilot has been operated for one year now to achieve a set of pre-defined objectives. During this period, a comprehensive data acquisition program was conducted and collected data from wells and reservoir performance was analyzed to address key uncertainties related to miscible CO2-EOR injection process.

Upon the completion of the project objectives in June 2010, a decision was taken to expand the project scope and target with new objectives that will help understanding another challenging anomaly in the oil fields (CO2 performance in the transition zones).

This paper shares the challenges faced, lessons learnt and experience gained during the implementation, operation, and monitoring of the First Miscible CO2-EOR pilot project in a heterogeneous carbonate oil reservoir in Abu Dhabi, UAE.
Automatic Trajectory Control in Extended-Reach Wells
Authors: Cockburn Colin , Matheus Justo , Dang Khoa Le
Published: September 2011

Prior to the advent of rotary steerable technology, directional drillers controlled trajectories using nonintelligent drilling tools such as downhole motors. Drilling a directional wellpath using this technology was relatively inefficient and had adverse effects on wellbore positioning and quality. The introduction of rotary steerable systems (RSS) enabled fast, efficient, and accurate wellbore placement and construction. This step change in steering technology tested the limits of human operators to assimilate the MWD data, compare the actual well trajectory with the planned, and take corrective actions to get back to the desired well plan.

RSS are very sophisticated tools with downhole intelligence. This intelligence provides the framework to implement advanced and automatic downhole trajectory-control algorithms. These have no lag times and can consistently perform accurate, efficient, and reliable corrective actions.

This paper presents the field results of the application of a novel trajectory-control algorithm which regulates inclination and azimuth downhole. The examples illustrate the impact of the technology on extended-reach wells. The paper ends with analyses, lessons learned, and conclusions from the field trial runs.
Development and Testing of a Novel Corrosion Inhibitor Technology for Acid Corrosion
Authors: Seth Kushal , Evans Brian , Hughes Baker , Gabrysch Allen
Published: September 2011

Corrosion of oilfield tubulars during a stimulation treatment is an acute problem as evidenced by weight loss, pitting, and cracking. Stimulation methodologies such as pickling, acid washing, matrix acidizing and acid fracturing can cause severe acidic corrosion mainly due to the low pH nature of the treatment fluid. The most common approach to mitigate corrosion is to add corrosion inhibitors to the stimulation fluids. To enhance the performance of acid corrosion inhibitors certain chemicals called corrosion inhibitor intensifiers are also commonly used. These intensifiers are sometimes partially soluble thus rendering them ineffective. This paper describes the evaluation of a new more soluble corrosion inhibitor intensifier designed to be effective in stronger acids for longer wellbore contact times.

The development and testing of such an inhibitor package is presented with the effects of varying test temperatures, types of stimulation fluids and metallurgies.

The paper presents results of acid corrosion testing performed on five different metallurgies namely 13Cr-S110, 718 Inconel, 13Cr-M110, 13Cr95 and 22Cr at 180°F and 220°F. Additionally the stimulation fluid ranged from 15% HCl, 13.5% HCl +1.5% HF and spent acid. The test period was extended to 24 hrs to test the effectiveness of the new intensifier package. The proper adsorption of corrosion inhibitors and intensifiers on the tubular can be altered by the addition of additives. To replicate an actual stimulation scenario the acid systems were tested with commonly used acid additives.

The results indicate that the inhibitor package was very effective in providing excellent corrosion protection in extreme test conditions. It was also observed that a large corrosion inhibiting effect was obtained with only a small proportion of synergistic intensifier used. The new, more soluble inhibitor intensifier technology fills the need to enhance corrosion protection in stronger acid environments for a wide variety of metallurgies and longer contact times.
Asset Optimization Metrics Card – A Unique Approach to Maximizing Production Efficiency
Authors: Desai Sameer F. , Abdulla Farida , Khatib Awwab , Sinha Satyendra
Published: September 2011

In this era of flourishing E&P activities it is imperative to provide stake holders from operations to management with latest and reliable information quickly. Information integrated from multiple sources, when automated and presented creatively reduces unproductive time for the decision makers for making correct informed decisions. On these lines a unique optimization metrics card has been developed in Kuwait Oil Company for an asset or area which has led to maximizing its production efficiency. Originally created as an excel based metrics report for the Greater Burgan Field, the new asset metrics card is a web based report card applicable for all fields of Kuwait with the ability to divide into increasingly smaller ‘production levels’ or conversely roll up to higher consolidated levels giving both staff and management the quick ability to assess what matters to them.

The asset metrics card consolidates the critical activity and capacity measures required to understand present & future ability to meet production targets. The metrics are a mixture of leading and lagging indicators that are all related to an asset being able to optimize the level of production through a facility by tracking groups of metrics that could be the precursors to future production (leading indicators) and metrics that represent post appraisals of past production activity efforts (lagging indicators).

The overlying purpose of the metrics card is to create awareness and a base for discussion among the field development stakeholders, from the smallest level to the highest on what are the activities that need adjustment to sustain or change progress towards maximizing production. All the metrics are related to or linked to another metric on the card and all metrics lead to the final measure of meeting production targets. These metrics are shared among multiple stakeholders and presents a customer/supplier relationship providing a common venue to discuss the balancing acts needed to meet the shared production targets.