bluuebunny/crossref_metadata_2025 huggingface dataset:
Adoption of RSS Speeds up Extended Reach Drilling in Mumbai High
Authors: Kali A. T. , Mishra A. K. , Sinha S. C. , Gupta N. J.
Published: December 2007

To increase productivity and profitability from Mumbai High field drilling of ERD wells had to be implemented. Using ERD techniques, new infill wells had to be drilled, which were otherwise not cost effective. Uses of Hi-tech tools were considered necessary to drain oil from distant subsurface locations, thus eliminating prerequisite of constructing new platforms for such wells. Further, these types of wells were presumed to serve significantly to achieve new enhanced production from the reservoir.

Experience of drilling an ERD well in 1995 with the available drilling tools and conventional mud system conveyed that these wells could not be drilled to longer departures of 2 Kms from platform to L-III reservoir level owing to onset of complications like formation collapse and stuck pipes before reaching the target. Even casing could not reach bottom due to the swelling in shales which were exposed for a prolonged duration. Feasible departures from platform were of the order of 1500 to 1600m only. However to enhance production in limited time, the need was to drill wells from an existing wellhead platform to reach a substantially far subsurface location in the reservoir. A tool was needed which can drill a well up to 2 Kms departure at landing point so that oil can be drained from a subsurface location as far as 3.5 Kms, keeping 1.5 Kms as drain hole. To overcome previous constraints in drilling, Rotary Steerable System (RSS) was adopted in the year 2003 and its use has reduced the drilling time of extended reach (ERD) wells noticeably as compared to previous wells. Targets from platform to entry point at producing reservoir L-III has been increased to 2.2 Km and total well length to 3.5 km. 12 ¼" section of 1597m inclined at 75° was drilled successfully in one week with the Rotary Steerable System and Glycol mud as drilling fluid. Drilling time has been additionally reduced by 3.25 days with oil Base mud used with Rotary Steerable System. The average number of drilling days, which were 95.87 in 95–96, has been reduced to 45 days today. The system have been found indispensable

for drilling ERD horizontal wells of lower layers of L-III in Mumbai High and it's adoption in 8½" hole size have opened the possibility of drilling a well with a departure of more than 5 Kms.
Optimizing Horizontal-Well Steam-Stimulation Strategy for Heavy-Oil Development
Authors: Luo Shanqiang , Baker Andy
Published: December 2007

The world still contains tremendous heavy oil resources. Ever-increasing energy demand requires more attention to be paid to harvesting all hydrocarbon resources, including heavy oil. The use of thermal processes has proven by far the most effective approach in producing heavy oil.

This paper proposes a practical steam stimulation strategy for heavy oil development using horizontal wells. In the proposed process, steam is cyclically injected through a horizontal well pattern to heat near wellbore reservoirs, and after a period of cyclic steam stimulation, one of the pattern wells is converted to a steamflooding well and the other pattern well is converted to a production well.

Through 3D reservoir simulation, this paper compares production performance of the proposed strategy with conventional cyclic steam stimulation (CSS), steamflooding (SF), and steam-assisted gravity drainage (SAGD).

A sensitivity analysis is also conducted to study the effect of oil viscosity and reservoir permeability on horizontal well production performance under different production strategies.
A Correlation Approach for Prediction of Crude Oil PVT Properties
Authors: Hemmati M. N. , Kharrat R.
Published: December 2007

Up until now, no specific correlation has been developed to estimate PVT properties of Iranian crude oils, nor do existing correlations estimate these properties with efficient accuracy. In this paper, however, an attempt has been made to develop a number of correlations for Iranian crude oils, using about three hundred PVT reports. These correlations were developed for bubble point pressure, solution gas oil ratio (Rs), and oil formation volume factor (OFVF) at bubble point pressure. The data used to develop the correlations cover a wide range of reservoirs with oil gravity of 18.8 to 48.34 API°.

It was found that the new correlations estimate PVT properties of Iranian crude oils much better than the published ones. The absolute average deviation for Pb, Bo, and Rs are 3.67%, 1.08%, and 4.07% respectively.

The results show that PVT correlations can be placed in the following order with respect to their accuracy for Iranian crude oils:

– Pb: Hemmati, Al-Marhoun3, Standing1, Hanafy4, Dindoruk5. – OFVF: Hemmati, Petrosky7, Standing1, Glaso2, Dokla6, Al-Marhoun3, Hanafy4. – Rs: Hemmati, Standing1, Al-Marhoun3, Dindorak5, Glaso2, Petrosky7.
Identifying Infill Locations and Underperformer Wells in Mature Fields Using Monthly Production Rate Data, Carthage Field, Cotton Valley Formation, Texas
Authors: Jalali J. , Mohaghegh S. D. , Gaskari R.
Published: December 2007

Recent increase in global demand for energy and the consequent high prices have prompted a need for improving the recovery from mature reservoirs. Identifying sweet spots in these fields for in-fill drilling and ranking the infill locations based on their potential productivity as well as underperformer wells as candidates for remedial operations are important for improving the economics of mature fields.

One of the most important issues that make analysis of mature fields quite challenging is lack of data. Production rate data is about the only data that can be easily accessed for most of the mature fields. The most accessible production data usually does not include flowing bottom-hole or well head pressure data. Lack of pressure data seriously challenges the use of conventional production data analysis techniques for most of the mature fields. The motivation behind development of the techniques that are presented in this study is to demonstrate that much can be done with only monthly production rate data in order to help the revitalization of mature fields.

Methods currently used for production data analysis are decline curve analysis, type curve matching, and history matching using numerical reservoir simulators. Each one of these methods has its strengths and weaknesses. They include significant amount of subjectivity when they are used individually in the context of production data analysis.

In this paper, intelligent systems are used in order to iteratively integrate the abovementioned techniques into one comprehensive methodology for identification of infill drilling locations as well as underperformer wells that would be the prime candidates for restimulation and/or workovers. Application of this technique to a large number of wells in the Carthage field, Cotton Valley formation is presented.
Multistage Fracturing System: Improving Operational Efficiency and Production
Authors: Seale R. , Donaldson J. , Athans J.
Published: December 2007

Over the last several years there have been many technical developments in horizontal completion methods. These developments have been designed to better stimulate the entire horizontal interval. For cased and cemented applications, composite plugs have provided the ability to segment the horizontal wellbore into sections and divert the stimulation as designed. However, the process of setting a plug on coiled tubing (CT), perforating, stimulating and then repeating the process for the required number of stages to optimize production and then running back in with CT to remove the plugs can take weeks to complete. For open hole applications, horizontal stimulations have relied solely on bullheading in stages in an attempt to generate multiple fractures. This has proven in many cases to only stimulate certain sections of the wellbore leaving much of the horizontal section unstimulated.

A new completion system has been deployed in over 300 wellbores in various producing formations, such as sandstone, limestone, shale, dolomite and coal. This system uses a series of mechanical open hole packers deployed on the production liner with fracturing or stimulation ports located between the packers that allow for stimulation in each desired interval. Without the requirement of cementing the liner in place, all the problematic issues associated with cementing are eliminated. Additionally, the use of mechanical packers provides positive mechanical diversion at high differential fracturing pressures. The system has also been designed, so all of the fracturing or stimulation treatments along the horizontal wellbore can be pumped in one continuous operation, thus minimizing the associated risks and optimizing the efficiencies of both the personnel and equipment needed to perform the work. This paper will detail the operational efficiencies and reliability of this novel completion system, as well as analyze the cost benefits and production increases that have been noted.
An Intelligent Portfolio-Management Approach to Gas Storage Field Deliverability Maintenance and Enhancement: Part One—Database Development and Model Building
Authors: Malik Kazim , Mohagegh Shahab , Gaskari Razi
Published: December 2007

The main goal of this paper is to modify and apply the state-of-the-art intelligent, optimum portfolio management to the gas storage field in order to optimize the return on investment associated with well remedial operations. It continues the development of a methodology for candidate selection and stimulation design and optimization using Artificial Intelligence techniques.

The data of an actual gas storage field was used to test the results. The project data include Well-bore, Completion, Perforation, Stimulation, Well-test and Reservoir Data. To make candidate selection for gas storage fields operators predict the effectiveness of the stimulation commonly using three parameters. One in Peak Day rate second is Absolute open flow and third is change in skin provided permeability values in the field don't vary much. The software developed in parallel with this selection methodology includes an easy to use interface that allows the user to edit the data for a gas storage field, perform well-test analysis and use neural networks in association with Genetic optimization tool. The software ranks the well according to maximum change in skin value and recommends the best stimulation slurry based on the weitage given to the skin and cost of stimulation. A decision to select the ranked wells for re-stimulate can be made accordingly.
Identification and Analysis of Fields for Waterflood-Enhanced Recovery Efforts
Authors: Hall Rod , Ross Dwight , Stevens Greg , Muehlberger Steve
Published: December 2007

Changing economic conditions allow for a new examination of mature and abandoned fields to identify oil that is now economically recoverable (reserves). In mature oil producing basins there are many inactive or limited stripper production fields, all potential waterflood candidates.

We present a methodology of identifying such fields, quantifying the incremental waterflood production, and creating a field development plan. Production forecasts are generated in a timely and cost effective manner for development scenarios with Time Dynamic Volumetric Balancing methods.

The field reviewed and used as an example is the Belcherville Field. It is a Caddo Conglomerate, located in Montague County, Texas, discovered in 1946. Developed in the 1950's, 9 wells produced 3 mmbo of primary production before being abandoned in 1967. Production was from the channel deposits of the Caddo formation that are draped over a gentle anticline. A comparative study of 7 other fields in the same trend indicates waterflooding can recover and additional 84% of primary recoverable oil.
Optimizing Drilling Operations in the Arkoma Basin: Building on Success
Authors: Romo Louis A. , Bert David R. , Richard Cliff , Kuwertz Luke , Koederitz William L. , Card Kirk , Barton Steve
Published: December 2007

The Red Oak Field is located in the Arkoma Basin in Southeastern Oklahoma. The Field recently exceeded peak production levels in what was previously deemed a fully developed reservoir, through an ongoing successful infill drilling program based on the use of three-dimensional (3-D) seismic. Moreover, the redevelopment program has surpassed the 100 well mark and has delivered some high rate gas wells.

The field may be characterized by its dry gas and multiple pay horizons in what has long been known to be "crookedhole country". In situ compressive strengths range from 10,000-psia through the Pennsylvanian to 55,000-psia through the Ordovician.

Much work has been done in the past to optimize air drilling operations for shallow wells; however, as deeper horizons are exploited new technologies have been implemented in order to deliver continuous improvement.

Drilling improvements in recent years have included the introduction of a state-of-the-art drilling rig, further optimization of air drilling operations and the introduction of Polycrystalline Diamond Compact (PDC) bits. A down-hole vibration mitigation effort was also initiated which yielded improved bit runs and the identification of micro-tortuosity and weight transfer issues. Vibration mitigation resulted in the redesign of bottom hole assemblies (BHA) and the optimization of bent-housing steerable-motor angle settings.

Rig rates have increased over time, along with the need for designer wells. Rotary Steerable Systems (RSS) were therefore implemented to address these issues. Initial attempts indicated that RSS were not able to overcome the formation tendencies in 3-D space. A detailed investigation resulted in the hypothesis whereby speeding up the RSS with a motor would provide enough side force with a push-the-bit system to overcome formation tendencies. Real-time Mechanical Specific Energy (MSE) measurements were used in conjunction with the implementation of a Powered Rotary Steerable Systems (PRSS) and revealed the fact that the full benefit of the RSS was not consistently realized (mostly due to the extreme nature of the drilling environment). As such, prototype extended-gauge PDC bits were designed in order to further reduce down-hole vibration, improve well bore quality and bit performance. The result has been sustained top quartile performance, a state drilling record and the continued growth of a mature field.
Permeability Damage Due to Water Injection Containing Oil Droplet and Solid Particles at Residual Oil Saturation.
Authors: Ali Mohammad A. J. , Currie Peter K. , Salman Mohammad J.
Published: December 2007

Re-injection of produced water is of increasing importance as water cuts continue to increase worldwide. It provides an environmentally acceptable solution to the disposal of produced water, and contributes to pressure maintenance when injection takes place into the reservoir itself. Injection can take place under matrix injection or fracturing conditions. In both cases, the performance of the injection well and the distribution of the injected water are strongly influenced by the build-up of formation impairment around the wellbore or the fracture face. Solid particles and small oil droplets dispersed in the injection water are deposited in the formation by a process of filtration, and therefore will cause this impairment.

As part of a study on formation damage, different concentrations of oil droplets and hematite particles suspended in water were injected into sandstone core samples. A particle analyzer was used to measures the inlet and outlet concentrations of each particle type, concentration and size. The analysis confirms the high impact of oil concentration with the presence of solid particle on permeability damage. Preparation of oily-water emulsion is very challenging to achieve without chemical agents or mechanical devices. The presence of solid particles present in oily-water emulsion act as emulsion stability agents. Hematite particles being oil-wet, improved emulsion stability. Permeability impairment due to oily-water alone at residual oil formation is insignificant, and the size of oil droplets does not play a big role in injecivtivity decline. However, oily-water containing solid particles causes severe permeability damage. Furthermore, if the deposition of solids increases to a critical concentration, it could create a high differential pressure mobilizing some of the trapped residual oil.
Underbalanced Drilling Successfully Implemented on First Dual Lateral Well in Libya
Authors: Safar Hussein , Azhary Sadek , Hijazi Ahmad , Qutob Hani , Chopty James , Pham Chau
Published: December 2007

The B24 well in the Fidaa Field was the first dual lateral underbalanced horizontal well drilled in Libya and the second well of Zueitina Oil Company's (ZOC) underbalanced drilling campaign.

The targeted reservoir "Facha" is partly depleted after 23 years of production to a 7.2 ppg equivalent mud weight. Nitrified diesel, a two-phase drilling fluid, was used to drill the reservoir section of the B24 underbalanced to avoid circulation losses and formation damage. Real time LWD was crucial for geosteering the well path in a complex reservoir structure and real time annular pressure measurement was also necessary to ensure the underbalanced condition was maintained throughout the entire UBD drilling phase.

Two 6" horizontal drains were drilled successfully with 2053" and 1517" drain lengths. Integrated efforts of ZOC and service companies of various disciplines during planning and operation stages of the well led to the success of the project. No QHSE incidents were reported and the productivity of the well was enhanced significantly.

The B24 well's production alone contributes to over 30% of the total Fidaa field production.
The Effect of Pore-Scale Heterogeneities on Carbonate Stimulation Treatments
Authors: Ziauddin Murtaza , Bize Emmanuel
Published: December 2007

Most carbonate reservoirs are heterogeneous at multiple-length scales. These heterogeneities strongly influence the outcome of acid stimulation treatments which are routinely performed to improve well productivity. However, most previous studies reported in the literature have focused on investigating the effects of injection rate, temperature, and fluid properties and few have focused on the influence of rock properties on stimulation treatments. This study primarily explores the influence of pore scale heterogeneities on stimulation treatments. Some results on the influence of core scale heterogeneities are also presented.

Core samples from eight different carbonate rocks were selected for the study. Samples were characterized for mineralogy, texture, fabric, porosity and density distribution using Nuclear Magnetic Resonance (NMR), Computed Tomography (CT) scanning, Scanning Electron Microscopy (SEM), mercury injection as well as resistivity measurements, chemical testing, etc. Each sample was then classified into a Reservoir Rock Type (RRT) which is primarily based on the porosity spatial distribution (PSD) in the carbonate. Each RRT represents a group of carbonate rocks with similar porosity spatial distribution and is expected to exhibit similar behavior to fluid flow and, therefore, to acid dissolutions. The 8 carbonate rocks investigated in this study represent 6 different RRTs.

Each carbonate type was treated with reactive fluids. Two different sets of coreflow tests were performed on 6 x 1.5 inch plugs. The first set of experiments involved determination of the evolution of permeability with porosity for the RRT. In these experiments the core was treated at high injection rates with a fluid of low reactivity. Injection at a high flow rate ensured uniform dissolution of the medium. Porosity was monitored by analysis of the effluent and permeability was monitored by the pressure drop across the cores.

The second set involved determining the acid breakthrough curves for each of the carbonate types using HCl (hydrochloric acid) as the reacting fluid. The characteristic pore-volume to breakthroughs (PVBT) and the wormhole velocities were obtained for each carbonate by injecting acid at different flow rates.

The results of the tests confirm the original hypothesis that the response of the carbonate rock to acid depends on the RRT it belongs to. In other words, rock samples with similar PSD exhibit similar trends in PVBT. The significance of the results to the design of matrix treatments in carbonate reservoirs is discussed.
Possible Alteration of Tight Limestone Rocks Properties and the Effect of Water Shielding on the Performance of Supercritical CO2 Flooding for Carbonate Formation
Authors: Zekri Abdulrazag Y. , Shedid Shedid A. , Almehaideb Reyadh A.
Published: December 2007

This work presents results obtained in a laboratory study investigating the possible alteration of tight limestone cores properties such as porosity, permeability, and wettability; and the effect of water shielding on a water driven slug of super critical CO2. Reservoir condition corefloods were conducted using actual rock cores and fluids obtained from a field in Abu Dhabi at 4000 psia and 250 °F. Recovery from core floods and the permeability and porosity before and after the flood were measured to examine the effects of SC CO2 flood on the tight composite limestone cores. Oil samples produced in the experiments were analyzed using gas chromatography (GC) to assess the mechanism of CO2–improved oil recovery. The characteristics of relative permeability were measured prior to and after SC CO2 flood. Changes in the relative permeability characteristic were used to evaluate the effect of SC CO2 flood on the limestone rock wettability alteration. Oil/water interfacial tensions (IFT) measurements as function of pore volume injected were conducted to evaluate any possible changes in interfacial forces due to the SC CO2 flooding.
Ultradeep Drilling Pushes Drillingstring Technology Innovations
Authors: Jellison Michael J. , Chandler R. Brett , Payne Mike L. , Shepard Jeff S.
Published: December 2007

Drilling ultra-deep (UD) wells places significant requirements on the drill string. Lengthy drill strings lead to high tensile loads which can lead to slip crushing of the drill string, hoisting capacity issues and drill pipe collapse capacity concerns at the blowout preventer (BOP). BOP shear rams may also have difficulty shearing today's high strength, high toughness drill pipe. BHA connection failures pose greater risk and cost at UD well depths.

This paper analyzes the many challenges associated with drill string designs specifically for UD drilling. It presents emerging drill string technologies that are solutions expected to increase depth capability for the industry's continued advancement of deep drilling operations.
A Quantitative Model for the Effect of Wettability on the Conductivity of Porous Rocks
Authors: Montaron Bernard
Published: December 2007

Reservoir rock wettability is an important parameter to consider for oil recovery optimization. The great majority of sandstone formations is known to be strongly water-wet. In contrast, most carbonate reservoir rocks are believed to be mixed-wet or oil-wet to some degree with a non-uniform distribution of the wettability in the reservoir. Despite the importance of this parameter there is currently no proven quantitative logging technique that can provide a continuous wettability log.

A detailed analysis of a new model for the conductivity of reservoir rock called the ‘connectivity equation’ is provided in the paper. Similar to Archie's law this simple model has only two parameters: An exponent called the conductivity exponent μ, and the water connectivity parameter Cw. Under some conditions Cw can be equal to zero and the equation becomes identical to Archie's law in its simplest form (n = m = μ). However, in the general case the model is fundamentally different from Archie's law because in the connectivity equation resistivity is only a function of the water volume fraction. Cw is shown to account for water connectivity effects in the pore network. These effects are encoded in the expression of Cw with three terms linked respectively to 1- the ‘super-connectivity’ of micro pores in micritic grains for carbonate rocks, or the super-connectivity created by shale in shaly sandstones, 2- wettability effects in meso/macro pores, and 3- the low connectivity of vuggy porosity. This model is compared with published data and is shown to correctly account for most situations, including ‘non-Archie’ rocks such as low resistivity pay in carbonates, strongly oil-wet rocks, and the dual water model for shaly sands. A good correlation between Cw – obtained from a combination of wireline logs – and wettability measured on cores is found on data from a Middle East carbonate reservoir.
Multiskilling as a Key Factor for Economically Viable Operations in a Mature Oil Province: Oseberg East as a Case Example
Authors: Dagestad Jan Ove , Saeverhagen Erland , Nathan Eugene , Knutsen Sigurd
Published: December 2007

Innovative solutions for development of new technology and business models are needed to meet the economic challenges of declining production from the mature North Sea oil province.

Bed space limitations imposed by platform redesign and modification at Oseberg East as part of the operator's improved oil recovery (IOR) strategy dictate a manning solution which significantly reduces persons on board (POB) if tail production is to be economically viable.

Previous POB reduction models have typically focused on reducing the drilling contractor and production-phase manning levels on the platform. This study extends operational efficiency by employing an Integrated Services Model that encompasses multiple service providers in addition to the drilling contractor. Considering the entire crew in the context of "manning by tasks instead of manning by services" results in a substantial reduction of headcount whilst maintaining quality of execution.

The solution developed covers directional drilling, downhole fluids, cementing, logging while drilling and completion operations, as well as drilling contractor and operator tasks. Emphasis has been put on transfering all work tasks that do not require physical presence at the rigsite to the onshore organization, for which use of modern communication technology is key.

The business model promotes operational efficiency between service companies and drilling contractor through the development of non-traditional working processes that transgress individual company boundaries. Employees from third parties will be cross-trained such that their presence onboard is utilized in mission critical operations even where responsibility for the operation does not rest with their home organization. Maximising the effectiveness of onboard headcount is considered a first step in developing long-term, cost-effective solutions that will help ensure the longevity of mature assets.

This paper describes solutions developed during the detailed planning phase of the Oseberg East tail production project, challenges to implementation, and expected benefits of the new service delivery model.
How Good is the Torque-Drag Model?
Authors: Mitchell Robert F. , Samuel Robello
Published: December 2007

Perhaps the only "standard" drillstring model in use today is the torque-drag model originally developed by Johancsik (1973) in 1984, and put in a standard form by Sheppard (1987). Because of the simplicity and general availability of this model, it has been used extensively for planning and in the field. This model is known to be an approximation of real drillstring behavior, in particular, that the bending stiffness is neglected, so the torque-drag model is often called a "soft-string" model. There have been many "stiff-string" models developed, but there is no "industry standard" formulation. Field experience indicates that the friction coefficient that matches torque data does not match drag data.

Why does this model work well in some circumstances, yet not so well in other cases? Part of the problem may lie in the description of the wellbore trajectory and the wellbore tortuosity. However, this study concentrates on the actual model formulation. The torque-drag model formulation has been reviewed in the context of a large displacement equilibrium analysis and it was determined that the model satisfies all of the force equilibrium equations, but only one of the moment equilibrium equations. The remaining two moment equations therefore provide objective criteria for evaluating specific torque-drag problems.

Several example problems with different inclinations and wellbore curvatures are studied to show how these criteria can be used to validate torque-drag models. Some general observations are made about torque-drag model applicability, but the real value of this study is the test criteria themselves.
New Choke Correlations for Sabryiah Field, Kuwait
Authors: Alrumah M. , Bizanti M.
Published: December 2007

Multiphase flow occurs in almost all producing oil wells and nearly every flowing well has some sort of choke to regulate the flowing rate, for the following reasons: (1) to maintain sufficient back pressure to prevent sand entry, (2) to protect surface equipment from high pressure, (3) to prevent gas or water coning and (4) to produce the reservoir at the optimum flow rate.

Present choke correlations are best used for the area where same conditions met with the data used to generate the correlations.

Inaccurate flow rate predictions could lead to gas/water coning, sand entry, and excessive pressures at the separator which can be a major factor of killing the producer well.

In this paper, actual data production tests from vertical wells from Sabriyah Fields in Kuwait, were utilized to establish a new generalized multiphase flow choke correlation that predicts liquid flow rates as a function of flowing wellhead pressure, gas-liquid ratio, and surface wellhead choke size. The primary proposed correlation exhibits more accuracy (only 4% average error) than the existent correlations. The multiphase correlation coefficient was determined as 89%. These results will undoubtedly encourage the production engineer to utilize the proposed correlation for future practical answers when a lack of available information, time, and calculation capabilities arises.
Microfine Particles—An Alternative to Heavy Brines
Authors: Steele Christopher , Hart William L.
Published: December 2007

Packer fluids are used to provide hydrostatic pressure in the annulus for well control purposes or to prevent casing collapse. As such they must be capable of doing so for lengthy periods, be non-corrosive and capable of inhibiting corrosion.

Completion fluids are used to permit the completion operations of a well. These may involve running completion strings, setting screens, gravel packs, downhole valves etc. To function effectively, completion fluids need to be able to provide hydrostatic pressure for well control and must be non-damaging to the reservoir to prevent loss of productivity.

Historically, clear brines have been used for both functions. This is to obviate the chances of solids settling with the potential of:

Loss of hydrostatic pressure Plugging of equipment Plugging of and damage to formation permeability

However, the assumption that clean brines fulfil these objectives and fluids containing solids do not is misconstrued. At higher brine densities, corrosiveness, formation incompatibility, associated HSE issues and costs may mitigate against their use.

For instance, some bromide brines are naturally corrosive and require treatment with corrosion inhibitors to be rendered non-corrosive. Such inhibitors may be damaging to the formation by altering wettability or relative permeability. There are also HSE issues attached to the use of these brines.

This paper describes the formulation and application of fluids using microfine particles to produce fit-for-purpose packer and completion fluids, which minimise sag, corrosion & formation impairment, whilst maintaining hydrostatic pressure and well control.

Actual field work done using the microfine weighting agents, manganese tetraoxide with PSD's of ~1 micron D50 have been shown to provide packer & completion fluids, which meet the requirements described above.
HARADH–III: Industry's Largest Field Development Using Maximum–Reservoir–Contact Wells, Smart Well Completions and I-field Concept
Authors: Al-Kaabi Abdulaziz O. , Al-Afaleg Nabeel I. , Pham Tony , Al-Muallem Ali S. , Al-Bani Fahad A. , Hart Richard G. , Hembling Drew E.
Published: December 2007

The development of Haradh-III in the Southernmost area of Ghawar represents a major shift in paradigm in terms of the combination of the technologies. The field development combines four main technology features which include maximum reservoir contact (MRC) wells, smart completions, extensive use of real-time geosteering and I-field initiatives.

This paper describes the motivation, implementation, and post-production evaluation of this unique field development. In the case of Haradh-III, field development with smart MRC wells delays water encroachment, improves flood front conformance and recovery, lowers water production and long term development and operating costs. Bottom water encroachment into the wellbore is mitigated as down-hole Internal Control Valves (ICV), as part of the smart completion, are adjusted. This in turn lengthens the life of the well, allows sweep and recovery to take place in the reservoir below the horizontal wellbores through the most effective sweep process: the replacement mechanism by gravity. The objectives of the development are accomplished utilizing a reduced number of wells, minimizing the accompanying infrastructure therefore lowering the capital expenditure while reducing the operating cost by maintaining, on a long-term basis, a low-water producing system, all occurring in real-time and within the I-field environment.
Scale Control in Chalk Reservoirs: The Challenge of Understanding the Impact of Reservoir Processes and Optimizing Scale Management by Chemical Placement and Retention—From the Laboratory to the Field
Authors: Jordan M. M. , Mackay E. J.
Published: December 2007

The scale control challenges for a large North Sea carbonate reservoir are reviewed in this paper. Field data from a reservoir where the process of scale ion stripping between the seawater injection well and production wells is known to occur is studied in detail to identify if it is possible to predict the impact it has on scale management. Injection water sulphate ions are shown to break through eventually, but the seawater fraction at which this occurs varies between different wells. The impact of the various possible driving mechanisms, and the extent to which matrix and fracture flow contribute to the process, are described. The discussion is generalised to findings applicable to other carbonate systems.

The mechanisms of scale inhibitor retention when phosphonate, polymer, and vinyl sulphonate co-polymer inhibitor squeeze treatments are applied in this carbonate reservoir are outlined. Chemical placement represents the most significant technical challenge when performing scale squeeze treatments into fractured chalk reservoirs. Examples from over 50 field treatments applied in the reservoir, where both phosphonate and vinyl sulphonate polymer chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated a clear potential for significant extension in treatment lifetime by changing from a phosphonate to a vinyl sulphonate co-polymer-based scale inhibitor. The selection and qualification of chemical placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined.

A key factor in the success of such treatments is an understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs, and more recently probes have been developed which increase the rate of evaluation/interpretation. All these methods prove that the chemical is present in the brine when sampled, or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness and squeeze lifetimes, and provide the confidence the extend the period between scale squeeze treatments, and in some cases stop treatment were brine analysis alone would have suggested further scale squeeze applications.
The Optimization of Gas/ Steam Injection Using Numerical Simulation
Authors: Moussine Kamil , Ibragimov Nail , Khisamov Rais
Published: December 2007

Simultaneous injection of heated exhaust gas (mainly CO2 and N2) and steam is one of EOR methods used in Russia for heavy oil recovery. In this case the energy released by gas-steam generator is used more efficiently compared to pure steam injection. Another benefit of using this EOR method is an additional reduction of the oil viscosity caused by exhaust gases solution in oil. This technology is particularly efficient when used for the small reservoirs being developed by a single well.

Practical implementation of this technology is not always successful. One of the main reasons of failure is that parameters of the injected gas-steam mixture are far from being optimal.

This study presents results of numerical simulation of the gas-steam injection process, so called huff-and-puff injection. The aim of the modeling was to estimate an influence of reservoir geometry and heterogeneity as well as huff-and-puff injection parameters on oil recovery factor. The reservoir's and oil properties were typical for Volga-Ural oil province of Russia. The radial geometry was used in numerical simulation with model radius equal to 400 meters. The main results of this study can be summarized as follows: heavy oil reservoir development based on primary depletion is not profitable; EOR methods are needed;efficiency of the huff-and-puff gas-steam injection increases with oil column thickness increasethere is optimal time for well being shut-in after gas-steam injection, this time is dependant on volume of injected energy;the reservoir heterogeneity plays significant role in thermal oil recovery process.
Estimating Optimum Well Spacing in a Middle East Onshore Oil Field Using a Genetic–Algorithm–Optimization Approach
Authors: Tabatabaei Nejad S. A. , Aleagha A. V. , Salari S.
Published: December 2007

In developing phase of a hydrocarbon reservoir and planning for drilling the production wells, it is necessary to drill these wells in an appropriate spacing to achieve maximum economic revenues, during reservoir life span. Traditionally, the optimum well spacing has been determined graphically from a plot of economic return versus spacing among the wells. This paper derives an equation to solve this problem directly without the plot and presents an illustrative example for its application in a recent developed Iranian onshore oil field. Then we optimize achieved function using a genetic algorithm (GA) approach with an initial random population with 20 chromosomes and 100 generation number as main optimization engine in order to finding optimum well spacing versus maximum project NPV. Our procedure show a well-matched results with figures that calculated by project contractor achieving from a trial and error process during defining the field developing scenarios.
Smart Tool System Boosts Performance of Intervention Operations
Authors: McNicol Jim , McGurk Mark , Heisig Gerald , Donadieu Brian
Published: December 2007

In these times of record operating costs, stakeholders place paramount importance on avoiding unnecessary, unproductive trips in the well. In well intervention applications such as milling, cutting, washing over and casing exit work, the lack of accurate information about downhole conditions often leads to wasted time and money.

As wells become deeper, more tortuous and technically challenging to intervene, the need to know more about what is actually occurring at the downhole tools becomes even more critical. Traditional surface-based indicators and gauges often provide inaccurate readings of the forces exerted at and around downhole tools.

This paper discusses a new, MWD-style "smart" intervention performance sub that contains a variety of sensors and electronics that gather critical downhole measurements and transmit them to surface. The smart tool affords the operator a completely new level of control with real-time decision-making capabilities that can lead to more efficient and reliable wellbore intervention jobs and significantly reduce operators’ risk exposure.

The paper will describe the smart tool and present several case histories where the smart intervention performance sub was integrated into well intervention bottomhole assemblies. Data from the smart tool was then transmitted using mud pulse telemetry and viewed at surface. The same data was also transmitted onshore to a real-time operating center, thus allowing a broader audience of experts to witness the early field trial applications.

The field trials verified several capabilities. Vacuum filter operation could be observed in real time, casing windows could be quantified with a window quality indicator, lightweight fish could be identified in real time at the bottom of deep, deviated wells, and packer setting forces and overpull could be accurately monitored downhole in a variety of depths and deviations. This summarizes the capabilities explored during deepwater system integration tests.
The Event Solution — A New Approach for Fully Integrated Studies Covering Uncertainty Analysis and Risk Assessment
Authors: Elrafie Emad , White Jerry , Awami Fatema
Published: December 2007

Saudi Aramco is continuously implementing many new innovative techniques and approaches to assist in meeting the industry's increasing challenges. One of these innovations is the new study approach "The Event Solution." The approach leads to better synergy among different stakeholders and enables faster decisions that fully encompass the complex uncertainties associated with today's projects.

The Event Solution is a short, intensively collaborative event that compresses major decision cycles, reduces uncertainty and provides a wider range of alternatives solutions. The concept is simple: identify the most important objective and focus the collective skills and creativity of a team of experts on meeting that objective in a special event that lasts just for a few weeks. The team is enabled with the latest hardware and software in a large team room where they can work together. A facilitator leads the team with the process that helps them to see "The Big Picture" and understand what matters to the bottom line. The team composition is enriched with representatives from all of the stakeholders (including technical experts, management, and facilitators) so that the results can be concluded and implemented immediately, with maximum buy-in.

The Event Solution includes a detailed uncertainty analysis and risk assessment process that has been successfully implemented in many events. The most important deliverable of the Event Solution, however, is that all the stakeholders develop a clear and common understanding of the critical uncertainties, project risk, and the agreed plans to move forward—the decisions. This volume of work, which traditionally requires months or years, is completed in weeks using the Event Solution process.

This paper presents the elements and processes of this new approach. Critical elements to a successful Event Solution include software, workroom, team members, and a facilitator. Once the elements are in place, the facilitator leads the team through processes that include project preparation, parallel workflows, uncertainty analysis, critical information plans, project risk assessment, and mitigation plans. Note that uncertainty analysis is not a simple by-product of the study; it is an integral component of success. Techniques are presented that can be applied to any study.
Fit-For-Purpose Laboratory Core Analyses and Their Impact on Log Processing
Authors: Ma S. M. , Al-Hajari A. A. , Kersey D. G. , Funk J. J. , Bruno L.
Published: December 2007

Core analysis data determined in the laboratory are often treated as ground truth in processing logs. Experimentally, core data is procedurally dependent. For special applications, a laboratory core analysis program needs to be designed fit-for-purpose. For example, oil migrating into a water saturated reservoir is a drainage process while waterflooding an oil reservoir is a water imbibition process. Due to the combined effect of pore structure and wettability, hysteresis exists between drainage and imbibition. To mimic fluid flow and distribution in reservoirs, hysteresis of laboratory determined petrophysical properties have to be considered in processing logs across oil and water flushed zones.

In this study, a fit-for-purpose laboratory core analysis program for reservoir saturation monitoring was designed. Scanning curves of capillary pressure and resistivity index were generated in the laboratory and used in formation evaluation and reservoir saturation monitoring of a carbonate reservoir. Petrographic studies were also conducted to aid in understanding the effect of pore structure on rock properties. Two field examples are shown to demonstrate the added value of integrating the resistivity log analysis with fit-for-purpose core analysis data for improved formation evaluation and reservoir saturation monitoring.
Innovative Cutting Structure, With Staged ROP and Durability Characteristics, Extends PDC Bit Efficiency into Chert/Pyrite/Conglomerate Applications
Authors: Mensa-Wilmot Graham , Mikhail Boktor , Al-Saeedi M. , Sounderrajan M. , Al-Ajmi H.
Published: December 2007

Heterogeneous formations present challenging performance issues for PDC bits, specifically in terms of ROP and durability. With current PDC bit technology, the bit runs are usually short and slow1, even when BHA design and drilling processes are optimized.

The performance challenges associated with these applications get more complicated, when heterogeneity is due to the presence of chert, pyrite and/or conglomerates (CPC). In such situations, the industry has usually defaulted to roller cone (RC) bits. Compared to PDC bits, RC bits are more effective in CPC applications from a durability standpoint.

However, RC bits have not shown ROP superiority or consistency. Considering the effects of "drilling hours" on RC reliability, the lack of ROP superiority usually necessitates multiple runs/trips. This condition, which compromises drilling efficiency, has a huge negative effect on operational costs.

Extensive research efforts, aimed at improving drilling performance in CPC applications, have identified the need for specialized PDC bits. These bits, as will be presented and discussed in this paper, have staged performance characteristics – in terms of ROP, durability and stabilization. In addition, these bits have no "time dependent" reliability issues (as mentioned earlier for RC bits).

Comprehensive analytical and bit development processes, together with field supporting data, that validates the new technology's effectiveness in CPC applications, will be presented in this paper.