bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fit-for-Purpose Sealant Selection for Zonal Isolation in HPHT Deep Tight Gas Wells
Authors: Al-Thuwaini J.. , Emad M.. , Ekpe J.. , Jaffery M.. , Ong D.. , Taoutaou S.. , Ahmad B.. 
Published: February 2011

Abstract
Zonal isolation has extreme significance in the construction quality and life of a well. Achieving zonal isolation in deep high- pressure, high-temperature (HPHT) gas wells is a challenging task, and these wells need more attention to achieve zonal isolation than conventional oil or gas wells. In addition to following primary industry best practices, the selection of a cement system appropriate for the environment of the well is very significant. Trapped gas and oil between production and intermediate casing (abnormal annulus wellhead pressure) has been globally recognized as one of the serious challenges facing drilling and production operations. The issue is becoming even more serious since wells are aging and the integrity of the casing portion below the well head is increasingly affected by the shallow-water corrosive environment. The potential safety and environmental hazards of the abnormal annulus pressure, have encouraged LUKSAR (Lukoil Saudi Arabia Energy Limited) to review the current drilling and cementing practices, with the goal of minimizing the impact of the problem, thus improving well life cycle and reducing the frequent work-over interventions. The general guidelines set to resolve the problem focused on eliminating potential leakage paths in the completion and casing strings and emphasized the quality of the primary cementing, especially for casings set on the aquifer zones and production casings.
This paper discusses case histories and selection criteria for the different cement systems. It shows how high-performance lightweight sealant across weak zones, fiber-based sealant technology when lost circulation prevails, self healing sealant system where zonal isolation is extremely important, and flexible and expanding sealant for frac candidates are chosen for providing and maintaining well integrity in these extremely remote and challenging HPHT wells.
New Approach to Improve the Horizontal Drilling Reach
Authors: Vestavik O. M. , Syse H. , Hole O. , Aleksandersen J. 
Published: February 2011

Abstract
In order to improve the cost efficiency of petroleum exploration and production, it is required to develop improved technology. The Reelwell Drilling Method (RDM) is a multi purpose drilling method with a unique arrangement for Extended Reach Drilling and Managed Pressure Drilling. A conventional drill string with a special inner string forms a dual concentric drill string, which is used to remove drill cuttings from the bottom of the well. A separate hydraulic fluid system is used to push the drilling assembly forward using fluid pressure from the surface.
The development of RDM started in 2004 and has since then been through several full scale operations in Norway. In 2009 RDM was successfully used to directional drill the 8 ½" section of a land well. The proof of concept and the practical application on conventional drilling rigs has been verified, as well as the features of the system, such as:
- Managed Pressure Drilling (MPD) – Unique isolation using a new downhole valve solution. - Very precise well pressure management and flow control (gain/loss). - Efficient hole cleaning and cutting removal from wellbore - Efficient hydraulic traction and WOB control.
The RDM is currently planned to be used for drilling horizontal wells in Canada. The potential to increase the reach for horizontal wells is here further discussed.
Feasibility of In-Situ Combustion in the Mature SAGD Chamber
Authors: Oskouei S. J. , Moore R. G. , Maini B. , Mehta S. A. 
Published: February 2011

Abstract
Steam Assisted Gravity Drainage, SAGD, is a commercially successful bitumen recovery method that has transformed some of the vast Canadian oil-sand deposits into recoverable reserves. Several SAGD projects have been developed in Northern Alberta in the past few years and many more are in the planning stages. As the projects mature, new operational problems are revealed demanding new solutions. Due to operational restrictions, it is almost impossible to have the same growth rate in all steam chambers in a SAGD pattern. Hence, interference between a mature chamber and an adjoining immature chamber can become a problem. Steam leakage from the immature chamber into the mature chamber, reduces the thermal efficiency of the project and requires a solution to prevent the steam dissipation.
Filling the mature chamber with combustion gases is a possible solution for this problem. Carrying out in situ combustion in the mature chamber would not only create the needed combustion gases in the chamber but could also recover a substantial part of the residual oil in the mature chamber. It is also likely that the combustion would create a reduced permeability coke zone around the mature chamber, thus isolating it from the rest of the reservoir.
To evaluate the merit of this idea, an elevated pressure experiment was conducted using a two dimensional physical model. Conventional SAGD process was conducted in the model to develop a large steam chamber. Air was then injected through a horizontal well near the top of the model, into the SAGD chamber and a combustion front was established around the air injection well. By operating combustion in the depleted chamber, residual oil was mobilized and produced. The oil recovery was increased by more than 20% over the SAGD operation. Initiation and propagation of combustion was confirmed by a large increase in the temperature in the combustion zone. After unpacking the model, it was found that a coke layer was formed around the perimeter of the chamber.
Exploiting Natural Fracture and Fault Fairways in the Jean Marie Carbonate Platform, N.E. British Columbia
Authors: Wierzbicki R. , Todorovic-Maranic D. 
Published: February 2011

Abstract
This presentation will review the nature of fractures in the Jean Marie from thin section to the seismic scale and focus on the seismic methods used to detect and exploit these high permeability fairways. Drilling results and production indicators of fracture flow will be reviewed, and the controls on fracturing discussed.
The Jean Marie carbonate is an Upper Devonian aged carbonate platform that developed on the western margin of North America. Gas is regionally trapped in moderate porosity and low permeability stromatoporoid-renalcid limestone reef mounds and limestone intermound sediments. The pool has been developed using underbalanced horizontal drilling to minimize damage to the fine pore system in this underpressured reservoir. Advanced seismic techniques are being used to detect porosity zones and high permeability fairways which increase deliverability and recovery of gas from the Jean Marie carbonate. Variable well productivity has been observed in similar facies, as has high productivity in low porosity rock.
In the last five years, in the Kotcho area, Encana has been targeting natural fracture/fault networks in the Jean Marie. These zones of fracture enhanced and diagenetically altered carbonates have better permeability, and often better porosity. The fracture networks appear to have controlled the distribution of hydrothermal fluids which enhance the porosity and permeability of the carbonate via dissolution and recrystalization. Horizontal wells that encounter fractures generally have better deliverability and greater associated reserves. The use of seismically derived porosity and fracture detection techniques has improved the well planning and the frequency of discovery of higher permeability/deliverability zones.
Fracture detection is an important component in the development of the understanding of the permeability system in a reservoir. Fractures and faults can be high permeability production zones, or thief zones for fracturing programs, or barriers to flow if they are cemented shut. The techniques used by Encana in the Jean Marie can be applied to other reservoirs and other lithologies.
Non-Cemented Casing Tieback String Reduces Expense and Risk in Deepwater Operations
Authors: Hinkie Ron 
Published: February 2011

Abstract
The method of anchoring a tieback casing string using cement has been well documented. Industry standards for installing a tieback casing string usually have called for placing cement around the outside of the tieback casing string to provide a barrier against the potential of sustained surface casing pressure (SCP). The cement also is used to anchor the tieback casing string into the polished-bore receptacle during production. After cementing the tieback casing string, a cleanout trip is required to clean the inside diameter of the casing and to remove the landing collar and cementing wiper plugs.
A recent application in deepwater Gulf of Mexico (GOM) allowed a major oil and gas company to perform a step change in technology that enabled the operator to perform the function more rapidly and at reduced expense. Swellable packers were used instead of cement, providing a novel, cost-saving and risk-reducing approach.
This paper will discuss the use of swellable technology as an alternative method for anchoring a tieback casing string. This concept allows the operator to isolate potential downhole pressure away from the surface and to anchor the tieback casing string during production. By using swellable technology, no cleanout trip is required, which provides a substantial cost savings for deepwater operations. The unique approach also reduces the risk to the casing and drilling string from the removal of the cementing wiper plugs and the landing collar. The case history will provide the details of the new application and how it improved cost efficiency and enhanced operational safety.
Effect of Solution-Gas-Oil-Ratio on Performance of Solution Gas Drive in Foamy Heavy Oil Systems
Authors: Busahmin B. S. , Maini B. B. 
Published: February 2011

Abstract
Foamy oil flow occurs in primary depletion of heavy oil reservoirs as has been demonstrated in many laboratory experiments. It is thought to be an important recovery mechanism in several heavy oil reservoirs in Canada and Venezuela, which have shown higher recovery factors compared to what is expected from the normal solution gas drive theory. This work investigates the effects of several process parameters on oil production rate and recovery factor in foamy solution gas drive.
The parameters examined included gas-oil-ratio (GOR), saturation pressure, the rate of pressure depletion and the drawdown pressure. GOR was varied independent of saturation pressure by using different gases, namely, methane, ethane and carbon-dioxide. Each foamy oil system was fully characterized by measuring gas oil ratio, oil compressibility, live oil viscosity, surface tension and foam stability. A total of 10 solution gas drive experiments were carried out in 2-meter long sand-pack equipped with several intermediate pressure taps using different solution gases and varying pressure decline rates.
The results show that the foamy solution gas drive performance is affected by solution gas-oil-ratio in a counterintuitive manner. The oil recovery decreased with increasing gas oil ratio at fixed saturation pressure. At the same rate of pressure depletion, higher oil recovery was obtained with methane saturated oil than with carbon dioxide saturated oil. Ethane, which had the highest solubility, provided the lowest recovery factors. It was also found that the oil recovery factor did not decrease significantly when the saturation pressure was decreased from 3,500 kPa to 2,100 kPa.
An analysis of all 10 depletion tests revealed that the most important factor that affects the oil recovery performance was the drawdown pressure, which was defined as the difference between the average sand-pack pressure and the production port pressure. Results obtained with different solution gases and widely varying depletion rates fell on the same trend line when the final recovery factor was plotted against the average drawdown pressure applied during the depletion.
New Insight on the Depositional Environment and Facies Atlas of Aptian in a Super Giant Carbonate Field in the Middle East
Authors: El Wazir Zinhom , Vahrenkamp Volker C. , Mueller Klaus , Al Madani Noura , Al Shekaili Fatema , Messisha Abdelmalek , Bijaripour Aita , Funk Erich 
Published: February 2011

Abstract
The 3D architecture of flow units is a key parameter influencing production and recovery from oil reservoirs. Depositional facies and their 3D stacking patterns are commonly fundamental building blocks of flow units. Hence, the recognition of facies, and their placement in conceptual depositional environments is the basic requirement to establish 3 dimensional architectural models of reservoirs.
In order to establish facies, facies stacking patterns and the 3D architecture of a super giant field contained in the Aptian in onshore Abu Dhabi , detailed sedimentological and petrographic core description have been carried out using about 13000 ft of core from a total of 49 cored wells. In total 27 facies have been established using fabric and bio content. They have been placed into conceptual depositional models following an evolving platform to basin topography during transgressive, early highstand and late highstand phases of carbonate platform development during the Aptian. This paper presents a comprehensive facies atlas that contains for each facies a detailed description of fabric and bio content, core and thin section pictures, petrophysical summaries and an interpretation of depositional environment. The large areal distribution of core coverage over more than 800 square km paired with the location of the reservoir transgressing platform interior to basinal settings ensures a comprehensive coverage of facies typical for most of the Aptian.
The study developed an updated and unified facies scheme embedded in the existing interpretation of the depositional environments and high resolution sequence stratigraphy, and completed the core facies scheme definition which is understood as a fundamental criteria for the population of 3D static and dynamic model, in order to effectively enhance future reservoir development.
Supercritical CO2/Methane Relative Permeability Investigation
Authors: Sidiq H.H.. H. , Amin R.. 
Published: February 2011

AbstractThis paper presents extensive laboratory results of unsteady state displacement of methane by super critical carbon dioxide SCO2 in consolidated reservoir core plugs. The fluid flow of the both phases is presented in terms of relative permeability using explicit methods. The main objective of this study was to investigate the feasibility of SCO2 injection for enhanced gas recovery for a newly discovered gas field situated in the North West Shelf of Western Australia.The core-flooding experiments of SCO2-methane were carried out on three short plugs and one long vertical sample. The impacts of various parameters were broadly studied on the recovery efficiency and gas multiphase flow at pore scale. These were pressure, temperature, composition, injection-rate, and permeability heterogeneity. Results indicated that the recovery factor at CO2 breakthrough is a function of in situ gas composition, injection rate, and pore pressure. In contrast temperature, absolute permeability and core position factors moderately affected the recovery factor.A new power model has been developed for interpolating experimental gas-gas relative permeability data. This model can accurately account for subsequent gas compositional changes during the displacement process.
Addressing Reservoir Heterogeneities in the Development of Upper Jurassic Carbonate Reservoirs, Offshore Abu Dhabi
Authors: Lehmann Christoph T. , Al Hosany Khalil I. , Matarid Tarek , Sayed Mohamed I. 
Published: February 2011

Abstract
Detailed seismic interpretations and an integrated reservoir characterization study were performed on a field offshore Abu Dhabi which reveals new insights into reservoir heterogeneities, both laterally, as well as vertically. The new interpretations provide the team with new insights into the subsurface heterogeneities and address them during the development plan.
The Upper Jurassic carbonate reservoirs, offshore Abu Dhabi, exhibiting heterogeneities on different scales. The lower reservoir section is a large shoaling-upward sequence with an upward increase in reservoir properties. Smaller-scale sequences are superimposed and define the major flow units. Stromatoporoids build-ups or layers are intercalated in the upper part of the lower reservoir section. These layers are characterized by vuggy porosity and the intervals exhibit significant higher permeablities. The upper reservoir section is characterized by meter-scale sabkha cycles composed of mixed carbonates and evaporites. The major reservoir units are separated by thick continuous evaporite units which are regionally continuous. The smaller scale sequences which are the major flow units might be separated by evaporite layers or dense carbonate intervals. Reservoir quality in the major flow units is controlled by dolomitization and anhydrite cementation and further compartmentalizes the reservoir. Understanding the spatial distribution of these reservoir heterogeneities (depositional and diagenetic) is crucial for the development plan.
Reservoir heterogeneities, lateral and vertical, have a major impact on the placement of producers and water and gas injectors. Changes in reservoir quality create sweet spots but also lower productive interval in the individual flow units. The use of intelligent wells and new completion strategies will be also applied to monitor and control early gas and water break through within the field. Our current understanding of the reservoir heterogeneities, therefore, helps us to mitigate some of the subsurface uncertainties. These heterogeneities will be further appraised and mitigated during early field development.
Mishrif Diagenetic Trapping Potential in Western Onshore Abu Dhabi
Authors: Taher Ahmed , Azzam Ibrahim , Abdulla Noor Ali , Witte Johan 
Published: February 2011

Abstract
A diagenetic trapping style is proposed for an oil accumulation found in the Mishrif Formation in the southwestern part of onshore Abu Dhabi.
A diagenetic trapping scenario, which assumes updip sealing by cementation is much riskier than a structural trapping scenario, but has large up-side potential. Oil accumulations in diagenetic traps represent an equilibrium state between buoyancy forces trying to move oil through rocks and capillary pressures in the low permeable layer that resists this movement. The only requirement for a diagenetic trap to exist is that the capillary pressure in the sealing formation is greater than the migration (buoyancy) force in the reservoir rock. In addition to that, smaller pore throat sizes in the sealing formation and larger oil molecules, for instance the product of an early oil migration stage, in the reservoir, can enhance the sealing capacity of the stratigraphic trap and result in bigger oil columns.
The potential of this particular Mishrif prospect was assessed on the basis of regional analogs and a geological model was developed. The prospect was matured by the acquisition of a 3D seismic survey in 2004 (Fig. 1), with the aim to delineate the limits of the stratigraphic trap. A detailed seismic reservoir characterization study was carried out and porosity maps were prepared on the basis of a calibrated acoustic impedance cube. Seismic attributes were generated with the aim to detect the fault/fracture patterns in the area.
The Mishrif stratigraphic trap in southwestern onshore Abu Dhabi is highly prospective since it is located adjacent to the mature Shilaif kitchen in the Ghurab Syncline (Rub’ al Khali Basin). The Shilaif source rock, which is time equivalent to the Mishrif shelf facies (Fig. 2), was deposited under restricted water circulation and anoxic conditions. Basin modeling suggested that the timing of hydrocarbon charge from this kitchen into the Mishrif reservoir started as early as Late Miocene.
The Mishrif play prospectivity evaluation, including the detailed and integrated geological model and 3D seismic interpretation will guide future appraisal drilling. In addition, the knowledge gained from this study can serve as a basis for further exploration activities related to unconventional trapping styles in the Mishrif Formation.
Carbonate Reservoir Complexity Resolving through Static and Dynamic Data Integration for FFDP Optimization
Authors: Al Meamari Ayesha , Al Shekaili Fatema , Assreti Elamari , Al Nuaimi Nawal , Jasser Majdolin , Mueller Klaus 
Published: February 2011

Abstract
A giant Middle East Carbonate Field is producing since 47 years with more than 700 borehole penetrations. The reservoir is 400ft thick of Lower Cretaceous shallow water carbonates with large intra-shelf basin. The reservoir has complex internal architecture due to the formation and in fill of the Basin.
Although connected to a large aquifer, with production the reservoir pressure declined by almost a 1000 psi within 10 years. Peripheral injection started to restore the reservoir energy and sustain production. Injected water in the periphery naturally went into the most permeable layers causing uneven sweep both aerially and vertically. Especially in the progrades with sequence of porous/dense intervals and typical permeability range between 0.1-10 md, oil production could not be sustained with peripheral injection, resulting in dedicated pattern injection schemes.
The reservoir unit, subject of this paper, is geologically complex due ro-grading and oblique clinoforms intervened by dense subunits, overlain with high permeable unit. The unit was developed in the last 5 years using gas-injection line-drive in the northern flank (permeability less than 2 md) and inverted 9-spot WAG patterns. Production from the area has not reached the target rate based on simulation. In addition, some injectors are suffering from low injectivity and based on pressure response compartmentalization is an issue.
This study integrates newly acquired data through additional wells, 3D seismic reprocessing, updated stratigraphy studies, better understanding of the porous/dense correlation, updated static model and dynamic performance data (well testing, transient surveys, saturation logging, production logging, etc…).
Main conclusions of the study include: Lack of connectivity is largely attributed to completing wells in different clinoforms.Producers and injectors do not have uniform profile across the horizontal section.Injected gas in the WAG is not contained and has percolated to the upper unit.
As result of integrating the static and dynamic data, the newly developed model will be utilized to optimize well trajectories, reduce pattern size and study the merits of continuing the WAG injection scheme.