bluuebunny/crossref_metadata_2025 huggingface dataset:
Density Measurement of Vegetable and Mineral Based Oil Used in Drilling Fluids
Authors: Hussein Adil Mohamed , Amin Remy Azrai
Published: February 2011

Normally, calculated frictional pressure losses do not match actual frictional losses recorded during drilling operation. Discrepancies between calculated and measured pressure losses are more severe in operations where synthetic based drilling fluids are used because synthetic based drilling fluids density and rheology varies with changes in down-hole conditions. In order to deal with this phenomenon, a comprehensive experimental study was performed to predict the densities of vegetable base oil (derivative of ester), mineral base oil (commercially used in the formulation of drilling fluids) and their blend at elevated pressure and temperature. In the experiments, the temperature ranged between 80F-300F degrees F and the pressure ranged between 50psi- 5000psi. The data showed that when the pressure increased at the constant temperature conditions, the volume of the based oil reduced. The data analysis also shows the importance of introducing the effect of pressure and temperature on the density of the based oil for the pressure loss calculation during drilling activities. The blend of vegetable based oil with mineral based oil showed more tolerance in High Pressure High Temperature (HPHT) down-hole conditions. In addition to that, part of the study focused on developing an empirical linear equation that related density change in pressure and temperature. Liner regression technique was used in this purpose. It was found that the empirical equation was accurate in estimating the experimental result. On the other hand, it was observed that the mineral based oil sample was more compressible and subject to higher thermal expansion than the vegetable based oil and their blend.
Gas Lift Optimization Under Facilities Constraints
Authors: Djikpesse H. A. , Couët B. , Wilkinson D.
Published: February 2011

Gas lift optimization is often used to enhance production of mature oilfields consisting of multiple reservoirs. For efficiency, several of those reservoirs often share the same surface processing facilities. In such context, we wish to find the optimal allocation of gas lift over an entire network of wells and pipelines, while accounting for the constraints imposed by the reservoir operating conditions.

In this study, we describe a novel, cost-effective approach to perform such optimizations involving non-smooth models and subject to expensive constraints that might be simulation-based and as costly to compute as the objective function. After classifying all constraints depending on their computational cost, points not satisfying simple linear constraints are feasibilized before evaluating expensive constraints. A sequential lexicographic ordering is applied in which the linear constraints take precedence over nonlinear constraints and inexpensive nonlinear constraints take precedence over expensive ones, which in turn take precedence over objective function values. Two oilfield-production optimization examples serve to demonstrate that the performance of the proposed method is much faster than the traditional ones.
Understanding the Influence of Rock Stresses on Wellbore Inclination in Salt Formations: A Well Planning Approach
Authors: Omojuwa E. , Okoye E. , Ousseni A. , Odunuga A. , Osisanya S. , Ahmed R.
Published: February 2011

With the growing trend of pre-salt discoveries, some salt formations cannot be simply bypassed to get to the reservoir. A considerable thickness of salt of up to 15,000-ft is usually encountered in the deepwater areas. Salt structures embedded within the hydrocarbon prone formations have contributed to the complexities of well trajectory design and operations. Salt domes are impermeable cap rocks for petroleum accumulation but the stress distribution and geo-mechanical dynamics within and around them limit the success of directional drilling. Creeping is the major behavior of salt formations.

This study presents a new stress analysis model for rock salt formations based on the octahedral shear stress theory and von Mises failure criterion. The model determines the second deviatoric stress invariant called octahedral shear stress. The stress model also includes the Maxwell's Creep Model in the formulation of the time-dependent response of salt formations to changes in octahedral stresses within salt structures due to the inherent visco-elasto-plastic properties of salt. Results obtained from the stress model show that the octahedral shear stress values in salt formations prior to drilling are dependent on the three principal stresses exerted by neighboring formations while the octahedral shear stress values in the salt formations during or after drilling are dependent on the minimum horizontal stress, wellbore pressure, wellbore radius, and the radial distance from a selected stress center. The stress model can be used to estimate the extents and distribution of the octahedral shear stresses within and around the salt structures prior to drilling and after drilling using the available stress data from geo-mechanical models. The position and inclination of the wellbore can be selected in a less-stressed zone within the salt formation. The case study for this study is the 3D-geomechanical model of a salt diapir from the Officer Basin, South Australia, subjected to long period of deformation. This paper concludes with the description of the suitable bottom-hole assembly (BHA) and drilling practices for successful drilling through salt structures.
Deep Water Oil Exploration and Development Using Satellite Technology
Authors: Kio M. T. , Agboola A. O.
Published: February 2011

Satellite imaging has come a long way since the first satellites used to cover the earth surface explorer VII, was launched into orbit. From simple detection of key earth features to the pin point, precise stratigraphic of earth points or massive surface features, satellite imagery provides better and improved imaging of the earth surface with the ability to get spatial resolutions of less than 1m from low earth orbit (LEO) and repeated ground swaths which generate clear images from space. The benefits of the remote oil prospecting abilities presented by satellites shows its viability in obtaining oil information from hitherto inaccessible areas located either within hostile regions or in deep sea areas. The unsuitability of using exclusively traditional techniques like sonar in certain coastal areas makes space based oil prospecting a growing alternative. With the ability to launch cheaper satellites becoming more of a reality, different types of LEO sensors (optical and radio) can effectively contribute to all day and all weather prospecting and coverage from space. The cost of space based oil prospecting lessens the overall cost of oil production in terms of time (operation), the number of equipment involved and the human resource which goes to reduce the cost of production per barrel. The flexibility inherent in using these LEO satellites for this purpose is also highlighted in the fact that the satellites play other earth mapping functions along side providing information for oil prospecting. SAR satellites and even high resolution optical satellites use oil sleek images to determine presence of oil deposits and formation configuration.
Enhancing the Injection Profile in Rahama Field - First Time in Egypt
Authors: Shaheen Tarek , Hamdy Ahmed , Dilling Lambert , El Khalik Tamer Abd
Published: February 2011

Water Injection is considered to be one of the most important ways to enhance oil recovery. Although all of the Injector wells in Rahma field in Egypt were stimulated before using hydraulic fracturing however, they were still suffering from severe decrease in the injection rates which are far below the target.

As a first time to be done for Qarun Petroleum Company (QPC), a full technical study has been done to the field in order to identify the main reason for the severe decrease in the injection profile which was formation damage and high increase in the skin value. Based on the study done, a technical treatment was designed and Matrix Stimulation Engineering was implemented to the well Rahma-12 as the first candidate for Matrix Stimulation.

The results were successful, the injection rate increased in the well Rahma −12 from 280 bwpd to 3000 bwpd and in the well Rahma-10 from 300 bwpd to 2800 bwpd. These successful results encouraged QPC to implement the Matrix Stimulation treatment in all the injector wells in the Rahma field which resulted in great enhancement to the injection profile in the field.

This paper discusses the full technical study done to the field and the chemical tests done in the lab in order to design the best treatment to the formation. It shares the experience gained during the execution phase and new best practices that were implemented first time which resulted in a great success. Finally it provides a useful data base for the field and the Matrix Stimulation Operations which were done first time in QPC fields.
The Preferred Natural Gas Conservation Option: Underground Storage of Natural Gas
Authors: Atoyebi Temitope Mariam
Published: February 2011

The need to conserve energy sources has gained awareness in the world. Natural gas which is a kind of energy source is oftentimes wasted either in the form of gas flaring or venting, These practices had generated great concerns in the world.

The aim of this proposal is to emphasize the need to conserve natural gas through storage. The different types of natural gas storage methods were compared in order to select the most viable option.

The Underground gas storage method (UGS) was selected as the preferred option and it was discussed.

Most importantly, a software was developed to perform economic analysis for the different storage methods and the determination of the UGS performance evaluation parameters.
Exploring Opportunities for Indigenous Participation in the Implementation of the Nigerian Gas Master Plan
Authors: Akinpelu L. O. , Omole O. A. , Falode O. A.
Published: February 2011

The involvement of Indigenous Entrepreneurs and Host Communities in the Implementation of the Gas Master Plan will have far reaching effects on the Nigerian Economy. The consequences of the neglect of this crucial element in the Oil side of the business are well known – enclave nature of the Industry with no multiplier effect on the rest of the economy, virtual control of a strategic sector that generates over 80% of total revenue in the hands of competing IOCs with a multiplicity of interests, little technology transfer and minimal Human Capacity Development. Wide spread alienation and agitation for Resource Control manifested over time and the Country is just now struggling to contain the damaging effects on the Oil & Gas Industry. These mistakes need not be repeated in the Emerging Gas business.

Three stakeholder Groups were identified in the consideration of opportunities for Indigenous participation: The Indigenous Entrepreneur, the Host Community Contractor and the Host Community Residents. The segmentation of the different Stakeholder Groups is deemed necessary in order to focus on the specific interests of each Group.
Criteria for Selecting a Candidate Well for Hydraulic Fracturing
Authors: Heydarabadi F. Roshanai , Moghadasi J. , Safian Gh. , Ashena R.
Published: February 2011

Hydraulic fracturing is the process of inducing a highly conductive path from the reservoir to the wellbore, thus increasing the productivity of the wells. The final success of hydraulic fracturing greatly depends on candidate well selection. Accordingly, selecting the proper candidate well is of crucial importance. This paper sets a series of criteria for assisting the process of candidate well selection for hydraulic fracturing. The IPR and correspondingly productivity index variations after hydraulic fracturing as case studies of several wells in one of Middle Eastern oil fields have been studied in this work in detail.

This paper can be used in the selection procedure of oil and gas wells for fracturing treatments. A detailed modelling of hydraulic fracturing candidate criteria selection would facilitate the task of identifying a proper candidate for this expensive job.

The most important parameters suggested are the in-situ stress profile of the well, the magnitude and direction of the in-situ stresses and the formation permeability. In this study, the pre-construction of the inflow performance models of the fractured and non-fractured well is considered as a tool in candidate well selection procedure. Well models presented here show the extent to which hydraulic fracturing improves the production performance of the well.

The previous works concerning candidate well selection for hydraulic fracturing do not put all the deciding parameters together in a clear order. This paper tries to summarize all criteria which must be evaluated during the candidate selection process based on experience and careful observation of the previous successful and failed jobs.
Mechanical Stability Analysis of Directional Wells: A Case Study in Ahwaz Oilfield
Authors: Zare M. R. , Shadizadeh S. R. , Habibnia B.
Published: February 2011

Ahwaz oilfield is one of the southern Iranian fields in the Middle East that are located in reverse fault stress regime. Wells A and B are two deviated wells with same drilling conditions that produce oil from Bangestan reservoir in Ahwaz oilfield. Numerous cases of borehole instability, stuck pipe, and borehole collapse have been reported while drilling well B. These problems cause highly increasing of drilling operation cost of well B. However, well A has been drilled without any serious problems. To investigate and avoid these problems and improving operating costs of drilling, a comprehensive mechanical stability analysis is essential. To do so, a computer program is developed to analyze the mechanical stability of these deviated wellbores. The mechanical stability analysis reveals that in the reverse fault stress regime, drilling in direction of maximum horizontal stress is the most stable direction. But drilling in direction of minimum horizontal stress, leads serious borehole instability and borehole collapse. Comparing the results with trajectory of two deviated wells, show that well A has been drilled in direction close to the maximum horizontal stress while well B has been drilled in direction of minimum horizontal stress. As result well A must be more stable than well B. Base on the results the best drilling direction in Ahwaz oilfield is parallel to maximum horizontal stress.
Mechanistic Modeling of Annular Two-Phase Flow While Underbalanced Drilling in Iran
Authors: Ashena Rahman , Moghadasi J. , Ashena Rahim , Roshanai F. , Sarmadivaleh M. , Safian G.
Published: February 2011

The difficulty of maintaining the wellbore pressure should be overcome by precisely predicting the wellbore pressure. The empirical models used widely by UBD simulators give a large error and may not be extendable to other UBD cases. For this reason, Mechanistic modeling has been applied to two phase flow with a number of assumed values for the existent coefficients varying from one UBD case to another. Therefore, in this paper, a new comprehensive mechanistic model is developed mathematically for Iranian Oil fields to match the characteristics of the corresponding UBD jobs in Iran by modifying the constant values of Lage et al, Perez Telez at al., Mousavi et al. and Ansari et al. mechanist models. It is compared with Ansari et al, the specifically developed mechanistic model for use in South of Iran.

Since the mechanistic models use mathematical relations with assumptions for the values of the constants rather than pure empirical study of two phase flow, the mechanistic models developed and validated with data outside Iran are not good enough to be used. In this paper different constant values have been tested and the ones which have led to the least average absolute error have been picked up to present a specific mechanistic model for South of Iran.

The empirical models which have been developed outside Iran cause erroneous results. The results illustrate that the new mechanistic model predicts BHCP with an error much less than Ansari et al. Mechanistic Model.

In this paper, it is shown that the development of mechanistic models to predict the flow behavior of two phase flow and transition patterns is a necessity to escape the incompatibility of correlations with the regional flow restrictions. Also, the Ansari et al model's lower performance has been diagnosed and tried to be removed. Very few mechanistic models have been developed to respond to the fluid flow parameter prediction requirements for use in UB drilled wells of Iran.
Prediction of Lost Circulation Using Virtual Intelligence in One of Iranian Oilfields
Authors: Moazzeni A. R. , Nabaei M. , Jegarluei S. Ghadami
Published: February 2011

Nowadays, huge human needs for energy forced petroleum and drilling companies to drill deeper into the earth which means spending more time on drilling and passing through numerous layers with different layer characteristics to hit the target. Since major part of a well cost depends on the duration of drilling phase, an organized drilling program seems vital to save the time and cost. Occurrence of different drilling problems like lost circulation and pipe sticking may deviate the drilling operation from the schedule. Mechanical pipe sticking is likely to occur after complete loss.

Lost circulation is one of the common drilling problems in the industry which expose heavy expenses to the oil companies. This problem commences from beginning of the drilling and continues till putting the casing in place. Mud loss can occur in low fluxes up to complete loss that finally can lead to well blowout or severe pipe stuck. Freeing the pipes may waste a week or even more time from the rig. Thus, having accurate information about returned fluid and recording mud loss rate can be great help to prevent drilling problems from taking place.

Drilling fluid loss is affected by different factor that make modelling of mud loss suffered from analytical point of view. Thus, employing artificial neural networks which its capability in simulation of complicated phenomena is proven looks very effective. In this research, using drilling daily report of some wells in Maroun oilfield (South-west of Iran), attempts are directed to predict lost circulation in different areas of this field. Network results in prediction of drilling fluid loss show good compatibility with real data were recorded in drilling daily reports.
Cement Packer: A Key to Accessing Marginal Reserves in Brown Fields
Authors: Olatunde F. , Adegboye P. S. , Idedevbo K.
Published: February 2011

Most brown fields are now experiencing rapid decline in oil rate; also, the cost of drilling has escalated over the years, thus posing a challenge to drilling opportunities in brown fields. Over the years new field discoveries have been on the decreasing trend and this has prompted operators to start looking for ways to access reserves that were originally considered marginal and hence bypassed during the early stages of field development. As these bypassed reserves were not considered significant, most of the wells were completed leaving the "sub economic" potential above the packer. Accessing them now would typically require pulling the tubing through a major rig workover (MRWO). This is very expensive and as such, MRWO operations are challenged by the economics of the reserves in place.

The thru-tubing cement packer is an innovative and cost effective technique of accessing behind pipe opportunities in existing wells. So while not a new technology, it is new to Chevron Nigeria. The reason why it has not been implemented sooner is likely because until recently, we have been fortunate enough to have plenty of (MRWO) opportunities with solid economics. The combination of extremely high rig rates coupled with a significant drop in the price of crude oil has resulted in a need to look for other, less costly means to access additional reserves.

The cement packer operation achieves zonal isolation through rigless workover cementing. The use of Slickline perforation as opposed to the conventional E line further drives down the rigless operation cost thus improving the economics of marginal reserves. This low cost method of developing reserves is key in ensuring that operators extract as much value as they can from their assets.

This paper reviews two case studies in the Southern Offshore Area operations of Chevron Nigeria where the cement packer technology was deployed successfully. The cost savings realized is presented and further application of this technology to other areas is also discussed.
No Lost Time Injury: A Success Story of a Multi-Disciplinary Approach in Amenam Kpono Field
Authors: Bada A. J. , Abia D. , Igwe A. , Ugbebor J.
Published: February 2011

Amenam Kpono offshore platform is operated by Total E&P Nigeria Limited, (operator of the NNPC/TEPNG joint venture). Amenam Kpono is ISO 14001:2004 certified and has been consistent in high ratings in Internal and External Safety Audits. Oil and gas operations are associated with inherent risks. The hazards and associated risks become high when there are varied critical and simultaneous activities such as Coiled tubing operations, Separator sand jetting, Turn around maintenance, painting campaign, opportunity jobs and oil / gas production. The scope of the paper did not cover the technicalities of these high potential operations but emphasises on the safety approach during the planning, execution and the handing-over/demobilization phases of these operations. Hazards eliminations and risk control /reductions from the various safety elements: Organizations, Personnel, Equipment and Environment are in the effectiveness of multi-disciplinary approach using appropriate Safety barriers. Ensuring a ‘No Lost Time Injury" considering these critical operations is a continuous improvement on the Health, Safety and Environment management systems and the enhancement of the Safety culture in the field. The paper also focuses on various pro-active measures employed in achieving the No lost time injury and the impact/benefits to the company in terms of Legal, Image, Moral and Economics. Safety Culture development and the human factor were also analysed in relations to Injury prevention. In Amenam Kpono Field, various measures (Pro-active / Reactive) such as Safety Inspections, Safety Audits, Safety training, Safety observations, Accident investigations and sharing lessons, Job Safety Analysis, Safety meetings, Emergency Response and plans, Contractor Management, Personnel on board management all combined with the different roles played by all personnel culminate in the success story of No lost time injury. The Safety Statistics of Amenam Kpono Field were presented comparatively focussing on LTI and target settings for the various datas. Ensuring a multi-disciplinary approach to the functionality of the Company's Health, Safety and Environment management system has caused personnel to take ownership of safety and shares the responsibility of operational safety objectives follow-up/close-out.
Early Kick Detection Using Real Time Data Analysis with Dynamic Neural Network: A Case Study in Iranian Oil Fields
Authors: Kamyab Mohammadreza , Shadizadeh Seyed Reza , Jazayeri-rad Houshang , Dinarvand Navid
Published: February 2011

One of the important challenges in drilling a well is kick detection. In fact, ignoring the signs of a kick lead us to complicated problems in killing the well and consequently, if the kick could not be controlled a blowout may occur. Therefore, considering the early detective parameters seems crucial.

Kick happens because some parameters like tank volumes are changed when the time passes, so static neural network cannot predict this occurrence; therefore, using dynamic neural network, which incorporate the previous data could predict the system manner better than the static one.

In this paper, a dynamic neural network model is presented and good results with acceptable accuracy are shown. The model was trained with some Iranian onshore oil wells that kick was encountered in them. The kicks were predicted longer before it could have been detected by the drilling crew.
Optimization of Waterflooding Using Smart Well Technology
Authors: Meshioye Oluwafisayo , Mackay Eric , Ekeoma E. , Chukuwezi Martinez
Published: February 2011

The incorporation of the smart technologies in injection wells has not been widely considered before this work, hence the originality. The world's demand for oil product is increasing gradually and lack of new significant discoveries has made it imperative to look for secondary processes and better technology that will help increase oil production. One of the secondary recovery mechanism used all over the world is waterflooding. Waterflooding is used in nearly all the fields in the world, it is used after natural depletion, and it's used for pressure maintenance and volumetric sweep of the reservoir. Smart well technology is another technology that is assisting in increasing oil production, it's a non-convectional well with downhole instrumentation (sensors, valves and inflow control devices) installed on the production or injection tubing. This work presents a methodology where waterflooding is been controlled by smart injector well technology to help optimize or increase the net present value of the Field.

The optimization procedure was done on three different case studies of commingled reservoir having different layer characteristics; it involves vertical smart injector well and production well penetrating fully through the commingled reservoir. A set-up optimization procedure was applied, were rate allocation method was used at each zone of the smart injector well. In this research, the right rate allocation to each zone that gives the maximum Oil recovery or highest Net Present Value gives the answer to the Waterflood Optimization setback. The smart injector well use in this research has Inflow control Valves which can automatically open and close in order to meet certain reservoir or production requirements.

Installing Smart Completion on the injector well gives an opportunity to control all cases of early water breakthrough and reduce water recycling in some reservoir layers; which will ultimately lead to an increase of 2% − 8% in the Net Present Value and 6% − 9% Cumulative Production of from the field.

This Technology is highly recommended for Niger Delta fields to improve recovery and delay water breakthrough.
Determination of Water Salinities in Hydrocarbon Bearing Reservoirs of Some Niger Delta Fields - Nigeria
Authors: Oruwori A. E. , Ikiensikimama S. S.
Published: February 2011

The purpose of this study basically is to determine water salinity of some fields to be used for screening of candidates for reservoir performance monitoring jobs, and to make such data available for use in the future field development studies. In this work the methods used to determine the water salinity are: the use of log interpretation chart, interpretation of basic common open-hole logs and the use of log interpretation software. The water salinities obtained from these methods were compared with the produced water analysis salinity values from the laboratory. From the results obtained, there is a trend in salinity, and the trend in the hydrocarbon bearing reservoirs varies with the different reservoirs or fields of study and is greatly affected by the lithology of the formation (i.e. sand or shale) where resistivity reading was obtained from, and resistivity tool used for logging the various reservoirs.
A Systematic Workflow Process for Heavy Oil Characterization: Experimental Techniques and Challenges
Authors: Memon A. I. , Gao J. , Taylor S. D. , Davies T. L. , Jia N.
Published: February 2011

Heavy crude oil reserves are steadily gaining attention as the world's energy demand increases. The fluid characterization of heavy oil and bitumen is critical in deciding best extraction, production, and processing methods of a heavy oil asset. High viscosity, low API, low saturation pressure, and low GOR impose challenges in measuring fluid properties of heavy oil. Such challenges include fluid sampling, sample handling, cleaning and de-emulsification of heavy samples and slow evolution of gas from oil phase during pressure-volume-temperature (PVT) testing— e.g., constant composition expansion (CCE) experiment. Due to these challenges, the accurate and reliable fluid characterization of heavy oil becomes more difficult. Currently, no industry standards exist for heavy oil property measurements. More often, heavy oil property measurements are performed in the same way as black oil fluid property measurements. This poses a big risk in obtaining erroneous fluid properties measurement for heavy oils.

This paper summarizes the heavy oil fluid characterization technique that includes fluid sample handling, PVT analysis, fluid viscosity, emulsion and rheology, slow kinetics of gas evolution during CCE experiment, solvent solubility study, steam stripping study, and high temperature vapor-liquid equilibrium of oil-solvent-steam systems. The experimental methodologies, including the merits and experimental limitations for these measurements are discussed in detail. Example results of heavy oil property measurements for each technique are presented. Finally, a systematic heavy oil characterization workflow is proposed for various types of production processes such as cold depletion, steam flood and heavy oil flow assurance characterization.
Local Dissociation Experiments of Methane-Hydrate-Bearing Soil
Authors: Falser S. , Palmer A. C. , Tan T. S. , Ja M K.
Published: February 2011

Large amounts of gas hydrates are deposited in marine sediments and permafrost regions in many parts of the world. Their potential as a future energy source, but also as a geohazard and contributor to global warming has raised people's interest. The paper reviews the major methane hydrate test facilities and summarises their capabilities. It is reckoned that none of them can dissociate hydrates locally by a combination of heating and depressurizing while measuring their composition changes in it situ. These features are later revealed as the core elements of the new hydrate test facility at the National University of Singapore (NUS), which can simulate hydrates in up to 1500 m below sea water level and 350 m below sea bed or surface, dissociating them along a centred line source while measuring local pore pressure-, temperature- and density-changes. Its single components are described in detail.
Montney Fracturing-Fluid Considerations: Case History
Authors: Romanson R. , Riviere N. , Taylor R. , McIntosh G. , Wilson M. , Loran C. , Cockbill J. R.
Published: February 2011

The Montney gas reservoir presents exciting potential and is likely to become a critically important component of future gas supply. However, the Montney often presents variable and unique stimulation challenges. Unlike reservoirs like the US Barnett shale but possibly like the Muskwa in the northeast B.C. Horn River basin, recovery of water-based fluids can be a key issue to achieving economic production rates in the Montney.

Choice of fracturing fluid must be carefully determined for each area of the Montney, balancing economics with production response. One must always keep in mind that key reservoir properties can vary dramatically in the Montney, both as a function of geographic location and depth.

A presentation entitled "Montney Fracturing Fluid Considerations" was given at the 2009 CSUG conference, which summarized results of regained methane permeability vs. drawdown pressure and contact time with Montney core under representative reservoir conditions. Water-, foamed water-, and hydrocarbon-based fracturing-fluid systems were studied. Implications of the results as to choice of optimum fluid were discussed.

This paper presents field-production results of the trials conducted with fluid systems resulting in conjunction with the above study. The concepts and reasoning used to arrive at final fluid choices for field trials are discussed, as well as a theoretical interpretation of the field-production results.
Behavior of Depressurization in Type III Hydrate Reservoirs
Authors: Shahbazi A. , Pooladi-Darvish M.
Published: February 2011

Hydrate reservoirs have been categorized as Type I, II, and III; Type I with underlying free-gas, Type II with underlying freewater, and Type III that is sandwiched by impermeable formations. The most common type of hydrate reservoirs are probably Type III reservoirs, where there is no underlying mobile phase beneath the hydrate layer. Depressurization in Type III reservoirs is characterized by difficulty in reducing pressure over a large region because of limited available surface area for decomposition and low permeability in the hydrate. This is unlike to be the case in Type I and II reservoirs, where pressure could be reduced across a large surface area between the hydrate and the underlying free phase.

A 3D numerical model incorporating heat and fluid flow, along with kinetics of decomposition and (re)formation of hydrate and ice, is developed in this paper. Next, the solution behaviour of Type III hydrate reservoirs in response to application of the depressurization technique is studied, with the goal of understanding the interactions between fluid and heat flow and their effects on the decomposition region. This is achieved by exploring for similarity solutions in Type III reservoirs.

The results of this study indicate that the behaviour of Type III reservoirs is sometimes close to that of diffusion problems, suggesting that a similarity solution exists. This has also been shown to be the case in the literature. However, under some other conditions, it is shown that the solution to this problem is also identical to a travelling wave solution, which is another type of similarity solution often observed in diffusive-reactive problems that exhibit frontal behaviour and sharp gradients. Conditions leading to development of these two types of similarity solutions are identified.

The contribution of this work is in identifying the different solution regimes in Type III hydrate reservoirs. This could help to understand and simplify the modeling of governing mechanisms involved in the process of gas production from the most common type of hydrates.
Real – Time Geomechanics: Applications to Deepwater Drilling
Authors: Bagala S.. , McWilliam I.. , O’Rourke T.. , Liu C..
Published: February 2011

Lithologies under deepwater conditions usually show relatively reduced effective stress, due to the reduced lithostatic column. This translates into relatively narrow mud weight windows, driven mainly by shear failure or pore pressure in overpressured conditions, and by minimum horizontal stress gradients. Drilling operations should consider wellbore collapse, kick and losses as the primary geomechanics-related drilling hazards. These should be investigated and predicted during well planning, and should also be appropriately monitored during drilling, especially when an appraisal campaign will require highly deviated wells.

Real-time geomechanics is defined as a workflow that takes into consideration mud weight window planning, identification of geomechanics-related drilling hazards and possible mitigation actions, and, while drilling, operations monitoring by real-time data acquisition and interpretation, drilling occurrences detection, drilling practices revision, and the real-time update of mud weight window for further drilling. The authors present the case study of a drilling campaign in Chevron operated Rosebank Lochnagar Discovery, deepwater West Shetland, in almost 3,700-ft water depth. This campaign had the goal of proving the development concept of drilling horizontally in a field where the previous maximum inclination was only 35 degrees.

The planning phase consisted of mud window modeling using a mechanical earth model from offset wells. Potential drilling hazards were then identified and synthesised using a Drilling Roadmap as a drillling planning and management tool. The monitoring phase consisted of real-time detection, from analysis of logging-while-drilling and wireline data, of drilling hazards typical in the area, such as cavings, losses, and packoffs. Data interpretation required a multidisciplinary team of geologists, petrophysicists, geomechanics engineers, and drilling engineers.

The application of real-time geomechanics allowed an improvement in operations, safe drilling practices, and refined calibration of the 1D geomechanical model for further drilling campaigns.
The Science Behind Erosion Qualification Testing of Frac Pack Tools
Authors: Clem Nicholas J. , Hammer Aaron C. , O’Connell Maria M. , Amaral Anderson da
Published: February 2011

Frac packing tool erosion is a growing concern as more high-profile deepwater wells are completed using this technique. Today many deepwater wells require frac pack pump rates of at least 40 barrels per minute (bbl/min) with proppant loads reaching 300,000 lbm. As zone lengths are increased and multizone operations are performed, jobs requiring 60 bbl/min pump rates with proppant loads reaching 1,500,000 lbm are becoming more typical. The current frac packing tool designs must be optimized to accommodate the higher pump rates and proppant volumes required to complete these deepwater wells.

Extensive research and development, including computational fluid dynamics analysis and scale-model erosion testing, have led to the development of a new series of sand control tools that have been optimized for ultra-high-rate frac packing applications. Analyzing various patterns such as velocity, fluid path, erosion, and sand concentration at high rates helps identify critical areas within the system that require design optimization.

Results from full-scale erosion qualification testing of this new series of sand control tools are discussed. The qualification tests are designed to simulate extreme applications for tools in terms of pump rate, treatment volumes, and proppant properties, while testing conditions remain consistent with actual job specifications. The qualification test parameters were chosen to emulate and, in some cases, exceed the parameters of frac pack treatments currently being planned for the deepwater Gulf of Mexico. Erosion properties of the crossover, extension, and casing will be discussed, and depicted.
Co-Injection of Noncondensable Gas Improves ES-SAGD Performance in Shallow Oil Sands Reservoirs With a Small Top Water Zone
Authors: Alturki A. A. , Gates I. D. , Maini B. B.
Published: February 2011

The majority of oil sands are too deep for surface mining extraction; hence, in-situ techniques such as Steam-Assisted Gravity Drainage (SAGD) must be used. However, SAGD in low-pressure, top water, reservoirs shows relatively poor performance. To improve SAGD, solvent can be co-injected with steam, as in Expanding Solvent SAGD (ES-SAGD) leading to enhanced recovery, rates, and efficiency. Like most pressurized processes, a competent caprock is needed to prevent steam losses to maintain good efficiency and rates. There exist significant oil sand resources that are considered inaccessible because they are shallow (low-pressure) with little or no caprock with top water zones. Solvent addition allows reduced operating pressure, which makes it amenable for low pressure, shallow reservoirs. This research examines ES-SAGD, with non-condensable gas co-injection, in reservoirs with top water that has the potential to quench the chamber and stagnate oil drainage. The results reveal complex dynamics between the depletion chamber and overlying water zone and operating strategies that extend the life of the chamber thus raising the recovery factor. Low-pressure ES-SAGD operating strategies can be used to efficiently recover bitumen from shallow reservoirs with top water. A key finding from this study is that addition of non-condensable gas to ES-SAGD can significantly improve recovery, rate, and efficiency. Given the volume of shallow oil sands reservoirs with top water, development of processes to unlock this type of resource is important and critical to further growth of in situ oil sands recovery in Alberta. The results provide a technical basis to construct feasible low-pressure ES-SAGD processes for this type of reservoir.
Monitoring Flow and Completion Integrity of a North Sea Subsea HPHT Appraisal Well During an Extended Well Test Using Permanently Installed Fiber-OpticTemperature Sensors
Authors: Wood P.. , Simpson A.. , Holland B.. , Brown G.. , Rogers G.. , Anderson S.. , Balster E.. , Figueroa M..
Published: February 2011

Since the mid-1970s technology has enabled extraction of the UK’s oil and gas reserves in a cost-effective manner using subsea wells rather than individual platforms. In 2008, 43% of the UK’s oil and gas production was by subsea wells (The United Kingdom Offshore Oil and Gas Industry Association, 2010).

Centrica Energy performed an extended well test on a subsea high-pressure, high-temperature (HPHT) appraisal well in the North Sea and monitored the test using a permanently installed optical distributed temperature sensor (DTS) system. The high temperatures and pressures, together with a subsea installation, created specific challenges for monitoring the completion integrity and flow from the multizone reservoir during the well test.

In this paper the authors outline the deployment of the DTS system and present an interpretation of the acquired data. The completion was installed in one trip, with tubing-conveyed perforating (TCP) guns run at the bottom of the string. The firing of the guns, the completion integrity, and the fluid flow were monitored using a DTS optical fiber connected through the wellhead via an optical wet-connector and extending past the packer to the bottom of the guns. The same cable was used to operate a downhole electrical pressure gauge above the packer. Interpretation of the continuous temperature data enabled Centrica Energy to:

identify leaks at gas lift mandrels while pressure testing the production tubing during commissioning, allowing time saving decisions to be made on how to proceed with the installation. check that all the perforating guns fired correctly to confirm that the whole reservoir was open to flow. monitor the flow from different reservoir intervals over the 2-week well test to compare the flow profile from the reservoir to model predictions. minimize QHSE risks associated with a well intervention.
An Integrated Single-Well Approach to Evaluating Completion Effectiveness and Reservoir Properties in the Wind Dancer Field
Authors: Cherian B. V. , Claugus A. O. , Dilli M. , Mata D. , Sitchler J. C. , Alatrach S. , Neumiller J. L. , Panjaitan M. L.
Published: February 2011

Accelerating the learning curve in a fluvial tight-gas development program can be achieved by understanding the impact of reservoir quality and completion properties on well productivity. Too often completion changes are made over a small sample (statistical) wherein numerous parameters (proppant volumes/type, gel-loading, etc) are changed without clear accountability of the variation in local geology and reservoir quality. This complicates basic production analysis techniques and can be a costly practice to determine the direction in which optimization should proceed.

Various proppants, fluid types and design schedules were analyzed to quantify the impact of these designs on productive fracture half-lengths and conductivity. Calibrated fracture propagation models were also utilized to relate these productive properties (fracture length, conductivity and permeability) to stress profile, gel-loading and proppant types via fracture propagation models. The development of calibrated mechanical properties, petrophysical models and understanding of current hydraulic fracture and reservoir properties thus enabled redesigning of future completions and the analysis of these completions. This paper demonstrates the application of appropriate fracture propagation models, rate-transient analysis and production history matching techniques to understand the direction in which completion design changes must move to increase productivity.
Drilling a Better Pair: New Technologies in SAGD Directional Drilling
Authors: Zimmer C. , Person J. , Richter D. , Tilley J. , Bittar M.
Published: February 2011

The precise placement of well pairs is one of the most crucial factors in the successful execution of a steam assisted gravity drainage (SAGD) drilling program. A SAGD drilling program includes placing the producer well relative to the reservoir boundaries, as well as accurately twinning the producer with the injector well. Delivering on these high expectations in unconsolidated formations, such as the McMurray oil sands, requires a strong focus on technological innovation.

A common practice in drilling SAGD wells in northeast Alberta is to drill lateral SAGD pairs with conventional steerable mud motors and logging-while-drilling (LWD) resistivity measurements. Although this combination has delivered success, certain limitations exist in terms of wellbore quality and placement. At the Statoil Leismer Demonstration Project, several industry firsts were successfully implemented, including a combination of the newest and most cutting-edge directional, measurement, and LWD technology.

The keystone of these industry firsts was the application of a soft formation modified, point-the-bit rotary steerable system (RSS), used on 20 horizontal wells. Combined with an ultra deep azimuthal resistivity sensor, the RSS provided precise geosteering along the bottom bed boundary in the producer wells, resulting in improved reservoir capture and reservoir characterization. More on-bottom time enabled more efficient drilling and significantly reduced well costs. Smooth, almost effortless liner runs reflected the lack of tortuosity in the wellbore, made possible by the rotary bottom hole assembly (BHA). Improved directional control made uniform well separation possible between lateral pairs, thereby reducing the risk of hot spots and short-circuiting during SAGD operations. The use of an even-walled power section above the RSS increased the bit RPM for improved BHA responsiveness while minimizing casing and pipe wear. Overall, the results and lessons learned from the demonstration of these new techniques provide a clear indication of the progressive future of directional drilling in SAGD.
The Comparisons of Production Behavior of Gas Producing From Gas and Gas Hydrate Reservoirs
Authors: Bai Y. , Li Q.
Published: February 2011

A mathematical model is firstly developed to describe the hydrate dissociation, in which the effects of the flow of multiphase fluid, the kinetic process and endothermic process of hydrate dissociation, ice-water phase equilibrium, convection and conduction are considered. Based on the model, the comparisons of production behavior between gas and gas hydrate reservoirs are presented. Numerical results show that the gas rate of gas reservoir is higher than that of gas hydrate reservoir under the same condition. However, the period of stable production of gas reservoir is shorter than that of gas hydrate reservoir. The water rate of gas hydrate reservoir is higher than that of gas reservoir. Moreover, the moment that the water rate rises to the maximum value is later with the increase of reservoir initial pressure. Results also show that the difference of cumulative gas volume between gas and hydrate reservoirs decreases with the increase of the initial pressure of reservoir. When the initial pressure of reservoir reaches a certain value the cumulative gas volume of gas reservoir exceeds that of gas hydrate reservoir. The pressure depletion in gas reservoir is faster than that of gas hydrate reservoir due to the permeability reduction caused by the solid gas hydrate.