bluuebunny/crossref_metadata_2025 huggingface dataset:
Some Features of Capillary - Gravity Equilibrium in Layered Strata
Authors: Rublev A. B. , Prohorov A.Y. , Federov K.M. , Shevelev A. P.
Published: February 2011

Sometimes common determination of water/oil contact in a reservoir is not a trivial objective. For instance interpretation of logging data for Umenskoe oil field gave the anomalous distribution of oil saturation in J2 reservoir. The middle part of the reservoir between 22 and 50 m has the largest value of oil saturation. The reservoir is significantly heterogeneous, the averaged depth distribution of water saturation and permeability are presented on the fig. 1. The highest oil saturation correlates with a middle permeability of the reservoir. That is why the analysis of capillary-gravity equilibrium in layered reservoir was performed.

The equilibrium condition is characterized by fluids immobility and leads to the equation for pressures definitions [2, 5]: (1)Po-Pw=pc=(ρw-ρo)gz+Const

where Po, Pw - are water and oil pressures, pc - capillary pressure drop, g - gravity constant, z - vertical coordinate, pv, po - water and oil densities.

Capillary pressure drop is defined through the dimensionless Leveret function [3]: (2)pc=J(S)σcosθk/m

where σ - is the interfacial tension coefficient, Θ- wetting angle, к - permeability, m - porosity, J(S) - Leverett function; S - water saturation. In the equation (2) the expression in the denominator determines the averaged pore radius.

All laboratory results on capillary pressure investigations (there were seven experiments) were processed to determine a Leveret function. The final results are given on the fig.2. As it is shown the classic presentation of capillary functions is a reliable techniques, there was only one correction: the index in denominator is slightly less than 0.5. й взгляд, распределениям водонасыщенности в пласте.
Carbonate Acidizing: Conjunction of Macro and Micro Scale Investigations
Authors: Fedorov K.M. , Smirnov A.S. , Kremleva T.A.
Published: February 2011

Acid treatment of carbonates is a common operation for production stimulation. A lot of codetergents for reaction rate decrease, for redistribution of acid placement in heterogeneous reservoirs and improvement of injection profile were proposed. These technologies are directed on stimulation improvement and are based on the mechanism of the carbonate acidizing which was investigated in the works [1, 2].

According to the investigated mechanism in some cases the flow and reaction of acid solution take place only in limited number of pore channels enormously increasing their radius and conductivity. This phenomenon was call wormhole formation. The existence of such channels raises well productivity significantly higher than in the case when acid flows through the whole porous media.

The research of Fogler and Fredd [2] resulted that wormhole formation depends on dimensionless Damkohler number. The general definition of Damkohler number is the ratio of reaction rate to the inflow rate to the reaction surface. So the value of the number depends on problem geometry. In the experiments on core plugs acidizing the formation of one channel occurs for number value 0.3 [3]. Increasing the Damkohler number (for instance by flow rate decrease) leads to the rise of the number of wormholes. The main trend is acidizing of all pores and front type chemical reaction with the whole carbonate consumption behind the front. In the inverse case (Damkohler number decrease) the sweep of pore channels by acid flow also rises but the asymptotical solution in this case is minimal impact of acid on rock (reaction rate is too small in compare with flow rate).
Permanent Optical Reservoir Monitoring System, A Possible Solution for Basement Fractured Granite
Authors: Wai Hou Tham , Kok Kheong Ong
Published: February 2011

In-well fiber optic monitoring systems are designed to provide continuous, high performance and high reliability data measurements in hostile environments. Today, optical sensing is a proven technology and is widely accepted by the industry after almost 20 years since its initial introduction. Adoption and deployment of this technology has increased dramatically over the last 10 years. The global footprint for this technology can be extended by applying the optical sensing systems to the challenging environment of basement fractured granite due to its uncertainty in temperature and pressure from the deep fractures.
Innovative Multi-Zone Water Injection: The Enfield ENC05 Story
Authors: Gibson Daniel , Medd Daniel , McCarthy Tom , Toldo Benni , Moselely Phil , Pudin Victor
Published: February 2011

The Enfield oil development, on Australia's Greater North-West Shelf, has now produced over 50 MMBBL oil. Enfield has been developed with both downdip and updip injection wells for pressure support and recovery.

An injector / producer pair were drilled in 2009 to develop the Enfield Sliver South area. For the project to be economically viable the wells needed to drain two fault compartments. In particular, water injection into each compartment needed to be proportional to the expected reserves. Recovery was expected at approximately 1.7 MMBBL from Segment 3 and 3.3 MMBBL from Segment 4.

Due to the location of subsea infrastructure a single water injection well needed to be drilled from the west with the first sands intersected in Segment 3, the smallest block, and then Segment 4 which required the most injection. One solution was to drill a dual lateral injection well. However, the cost and difficulty with injection control of this option was prohibitive for the project. A horizontal well design using two sets of stand alone screens, with Inflow Control Devices (ICD's), was selected to access both fault blocks. This provided both the flow control and the sand control required for these reservoirs.

This paper highlights the innovative ICD solution adopted to achieve the required proportional water injection and avoid over injection into Segment 3 (at the heel). Various models were constructed to analyse injection scenarios with variables including; sand penetration and quality, compartment volumes, near wellbore skins, producer off take rates, and pressures.

Upon drilling the well, and obtaining reservoir data, the final completion configuration was selected. This included the placement of three screens with 6 ICD ports open per screen for Segment 3 (at the heel of the well) and three screens with 32 ports open per screen in Segment 4 (at the toe of the well).

Both Matrix and Fracture injection have been observed in ENC05. The well is routinely exceeding 30,000 BWPD, at fracture rates through the ICD's, into both compartments and successfully supporting the over 20,000 BOPD oil producer to the north. This was the first time high rate proportional control, including fracturing, has ever been done with ICD's to our knowledge.
The Salym Project
Authors: Deacon Andrew , Mackay Howard
Published: February 2011

This text was first submitted to the 2009 International Petroleum Technology Conference in Doha, Qatar where it gained an award, placed third for Excellence in Project Integration.

Some doubted that a foreign company could do anything innovative to add value in Western Siberia. Yet, the story of Salym Petroleum Development demonstrates otherwise.

The Salym project shows how an oil company achieved fast-track development and rapid production growth. Not only were the Salym fields developed and produced at a breathtaking pace, but it was achieved in an environmentally and socially responsible way, benefiting the local community.

At project commencement the mandate was tough: design and build the entire oilfield including infrastructure, early oil production of 0.75 million barrels and start full scale production all within 26 months, in an unfamiliar, remote and challenging environment. Projects of this scope normally take four years.

Production has since exceeded 160,000 bpd, an unprecedented development rate in the heartland of the Russian oil industry. How? By combining Shell’s expertise and technologies with Russia’s vast regional experience to get the best results. Most importantly, SPD adopted the philosophy that success comes from enduring, positive relationships with employees, partners, contractors, shareholders, government authorities and members of the community – partnerships where everyone wins.
Integrated Analysis Combining Microseismic Mapping and Fiber-Optic Distributed Temperature Sensing (DTS)
Authors: Holley E. H. , Zimmer U. , Mayerhofer M. J. , Samson E.
Published: February 2011

Mapping the microseismic activity during a hydraulic treatment is widely used to determine the geometry of the stimulated fracture network. Microseismic maps provide reliable information on the development of fracture symmetry, half-length, azimuth, width and height, and their dependence on the treatment parameters and reservoir characteristics. Beyond that, these fracture geometries are used to better understand fracture modeling and even production characteristics.

Fiber-optic-based distributed temperature sensing (DTS) arrays provide almost immediate updates of the near-wellbore temperature distribution in approximately one-meter intervals. In injection treatments, the near-wellbore temperature distribution can be used to determine isolation effectiveness, the relative amount of fluid each perforation cluster takes, fracture initiation points, and effective fluid diversion. In production analysis, DTS measurements can quantify production rates from each perforation interval, crossflow rates while shut-in, and fluid types recovered from each perforation interval.

The detailed near-wellbore results available through DTS coupled with the far-field geometry acquired through microseismic mapping provide an accurate picture of the completion effectiveness. Microseismic mapping results often show adequate resolution over a large area but lack the fine resolution that would allow it to identify near-wellbore effects in the meter range. When modeling and interpreting the treatment geometry obtained by the microseismic-event distribution, it is important to include the correct near-wellbore effects, which are readily accessible through DTS measurements. Combining the two diagnostic tools is valuable for real-time decision making, post-treatment analysis, and production analysis to assess the completion effectiveness.

Incorrect assumptions about perforation breakdown, fracture-initiation points, interval isolation, or limited-entry effectiveness can lead to misinterpretations of the microseismic results. Using both diagnostic tools provides firm answers to the overall completion effectiveness. This paper focuses on three distinct aspects of combining the analysis of microseismic mapping and DTS. The first is the real-time aspect, wherein real-time decisions and adjustments are made during the fracture treatment with the objective of manipulating the results towards the desired outcome. The second is using both tools to perform more accurate postfracture analysis, including calibrated fracture modeling, entry effectiveness, correct interval spacing, and stimulated reservoir volume (SRV) analysis. The third area covered is combining these diagnostic tools with a production analysis, which is acquired through analysis of the temperature data.
A Conceptual Development of a Slim Drill Ship
Authors: Mortensen Asbjorn , Kah Keong Alex Tan , Geok Soon Ricky NG , Dimble Abhijit Dnyaneshwar , Vincent Sudhan , Ostvold Tom Waitz
Published: February 2011

This paper outlines a proposal for a slim drillship optimised for re-entry into existing subsea wells. The ship is designed to perform intervention operations using wireline and coil tubing equipment, through a high pressure riser string between the ship and the subsea wellhead, for access to the pressurised well. The slim drillship is also equipped with machinery and tools enabling it to drill new hole sections inside existing wells, for example long horizontal extensions, using slim jointed pipe that enters the well inside its production tubing. A key feature of a slim drillship is its high pressure (HP) riser, giving intervention tools access to the well containing hydrocarbons, eliminating the need to kill the well first with drilling mud. This feature does also enable the ship to use Manage Pressure Drilling (MPD) methods.

The drillship is initially designed for 7500 ft of water depth as well as well depth below the drill floor of 22500 ft. This is believed to be a practical depth limit for some known subsea fields in the North Sea area, Mexican Gulf, Brazilian shelf and areas offshore West Africa, and future areas in South Asia. It is possible to configure the ship for deeper wells.

This paper focus on the drill floor layout and open deck areas for storage of tubulars and equipment. An open mast for hoisting is proposed in order to enable a large drill floor for third party equipment. The mast is telescopic so the ship can lower the crown block and pass through the Straits of Bosporus and the Panama Canal, enabling the ship to move fast between arctic locations and tropical waters without passing south of South America. A novel vertical pipehandling method is used, with cylindrical rotating setbacks at a lower elevation than the drillfloor, and offline stand building on this lower deck. The use of an open mast layout as opposed to an enclosed derrick gives access to the well centre for intervention equipment, and enables rapid turnover between various tools going into the well.
Experimental Study of Solvent-Based Emulsion Injection to Enhance Heavy Oil Recovery in Alaska North Slope Area
Authors: Qiu Fangda , Mamora Daulat
Published: February 2011

This paper is the report for the second stage research of nano-particle and surfactant-stabilized solvent-based emulsion experimental study for the heavy oil in Alaska North Slope Area. The core flooding studies under laboratory conditions were implemented after the bench tests, which is including the phase behavior test, rheology studies and interfacial tension measurement. And these studies provide the optimum selecting method for the nano-emulsion which could be used in the core flooding.

The experiment results suggest this kind of emulsion flooding is a good optional EOR (enhanced oil recovery) process for heavy oil reservoirs in Alaska, Canada after primary production, where heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems.

Core flooding experiments were performed on cores with varied permeabilities. Comparisons between direct injection of nanoemulsion systems and nano-emulsion injections after water flooding were conducted. Oil recovery information is obtained by material balance calculation.

In this study, we try to combine the advantages of solvent, surfactant, and nano-particles together. As we know, pure miscible solvent used as an injection fluid in developing the heavy oil reservoir does have the desirable recovery feature, however it is not economical. The idea of nano-particle application in an EOR area has been recently raised by researchers who are interested in its feature-reaction catalysis-which could reduce in situ oil viscosity and generate emulsion without surfactant. Also, the nano-particle stabilized emulsions can long-distance drive oil in the reservoir, since the nano-particle size is 2-4 times smaller than the pore throat.

In conclusion, the nano-emulsion flooding can be an effective enhancement for an oil recovery method for a heavy oil reservoir which is technically sensitive to the thermal recovery method.
A Novel Nondamaging Friction Reducer: Development and Successful Slickwater Frac Applications
Authors: Sun H. , Stevens R. F. , Cutler J. L. , Wood B. , Wheeler R. S. , Qu Q.
Published: February 2011

Friction reducers are commonly used in slickwater fracturing operations to minimize energy loss due to tremendous amount of friction between tubular goods and water or brine solutions during the pumping of very high rate of fluids. Currently almost all friction reducers used are high molecular weight polyacrylamide emulsions. Large amount of polymers is injected into the formation even at very low concentrations (typically 0.5 − 2 gpt) due to the large volume of a typical slickwater frac treatment. Concerns have persistently been raised over possible fracture and formation damages caused by the friction reducers. All current friction reducers, including copolymers, are polymers with C-C backbones, which are difficult to break. Tests show that these polymers, even in the presence of oxidizer breakers, cause formation damage.

A novel friction reducer featuring easily breakable chemistry has been developed to offer clean, non-damaging slickwater stimulations. This new non-damaging friction reducer, delivered also in liquid form for the ease of transportation and field operation, is very effective as a friction reducer, compatible with common chemical additives (scale inhibitors, biocides, clay stabilizers, surfactants, brines, etc) and stable towards mechanical shearing. This paper will present the product development details and lab tests on the effectiveness of the new friction reducer in water and various brines and its hydration profile at different temperatures, chemical compatibility and breaking profiles. Formation damage studies on tight sandstone and shale formation on this new friction reducer in comparison with the conventional ones have been conducted and will be discussed in the paper. Results show the non-damaging friction reducer degrades easily with conventional breakers and leave no damage to the formation. Several successful multi-stage slickwater frac completions have been performed with the new friction reducer and these field trials will also be reviewed.
The Selection and Optimization of a Surfactant Package to Maximize Cleanup of a High-Density Fracturing Fluid
Authors: Cawiezel K E. , Singh A. K. , Carman P. S. , Cutler J. L.
Published: February 2011

In the Gulf of Mexico, momentum is increasing for drilling and completing wells deeper than 25,000 ft and with bottomhole pressures exceeding 20,000 psi. High-density base fluids have become standard components of fracturing or frac-pack completions to achieve working pressures below 15,000 psi at surface due to equipment limitation. Stimulation designs for these deep, high-profile wells aim to achieve long fracture lengths using large treatment volumes. Cleanup and maximum recovery of the high-density fracturing fluid is a necessity to maximize the effective fracture length, and thereby the production potential after these treatments.

Interfacial tension, contact angle and wettability are the key parameters to consider when choosing a surfactant package for maximizing fluid recovery. Historically, the surfactant packages that have been used in conventional fracturing fluids generally focused on water-wetting or non-wetting and lower surface tension results.

This paper presents details of laboratory studies to optimize a surfactant package for high-density base fluids. Fluid recovery studies were done on a sand column along with the measurement of the contact angle and interfacial tension of high-density base fluid with various surfactants. Core flow tests were also performed to evaluate regain permeability and cleanup. The tests with optimized surfactant package resulted in more than 90% regain permeability with a high-density fracturing fluid system and correspond with the results from the fluid recovery sand column testing. Laboratory tests show that the synergetic effects of interfacial tension, contact angle and wettability together are more significant than any one individual parameter and that more surfactant is not always better.

Selecting and optimizing a suitable and compatible surfactant package enhances the recovery and cleanup of a high-density fracturing fluid, which can result in highly conductive and longer effective fracture lengths.
The Special Successful PCP Applications in Heavy Oilfield
Authors: Wu Bingchang , Li Xin
Published: February 2011

Due to some particular advantages, such as the maximum suitable artificial lift system for heavy and sandy wells, higher pump efficiency and power saving, PCP (Progressive Cavity Pump) is becoming one of the popular oil artificial lift system in recent years. PCP artificial lift technology is up to 12% all over the world averagely, and 50% in Canada. For normal heavy oil (viscosity ≤1000CPo), the oil can be lifted to the surface only using conventional PCP system. But for the more viscosity oil (viscosity ≥1000CPo), the viscosity and frictional resistance in the formation and annular (between tube and sucker rod) will induce a very big difficulty for the oil flowing from the formation to pump depth and from pump depth to the surface, so some assistant measures must be used with PCP system to lift the oil from downhole to surface.

For SAGD (Steam Assisted Gravity Drainage), CSS (Cyclic Steam Stimulation) and SFD (Steam Flooding Drive) wells, steamed gas is assisted to decrease the oil viscosity to enhance its fluidity. PCM Vulcain™ (PCP with metal stator and metal rotor) had been successfully applied in such kind of wells since 2007. And PCM PCP with 198 high temperature resistant elastomer had been successfully used in 4 CSS wells. In addition, several high viscosity wells are producing with normal PCM PCPs assisted with light oil mixing system, hot water injecting system and electricity heating system.

This paper will discuss the successful PCP artificial lift system applications with above 5 special assistant systems. This paper will be a guider for such kinds of special PCP technologies to be spread and applied widely in the world.
Downhole Electrical Heating System: Feasibility of Heavy Oil Implementation in Offshore Congo
Authors: Vielma W. E. , Congo Eni , Misenta M. E. , Ponticiello I. , Secco G.
Published: February 2011

The heavy oil reservoirs exploitation is one of the future targets of the major oil companies worldwide. Most of the heavy oil fields are produced through cold production methods leaving therefore significant amounts of unproduced reserves. To date different EOR techniques (like for instance steam injection or other thermal methods) are available to achieve higher recovery factors.

However, some technologies, like the downhole electrical heating have been recently improved, allowing cold production enhancement therefore maximizing the recovery factor without incurring on the high investments associated to the implementation of EOR. In order to increase the production of the heavy oil reservoir in the offshore Congo, a study of down hole electrical heating application has been carried out showing encouraging results.

The aim of the study was to evaluate the benefit associated with the application of this technology through the reservoir modeling. Significant results were achieved in terms of recovery factor increase.

The use of heat to increase the reservoir temperature showed good results in terms of heavy oil viscosity reduction starting from 1,000 cP at reservoir conditions (34°C) down to much lower values throughout the production time resulting in increased production rate and consequently, higher recovery factor from this reservoir.

The first application of this technology is foreseen in a long horizontal well section of about 600 meters length completed with production sand screen. The electrical heating mineral insulated three phase cables will be deployed throughout the horizontal well section by means of a dedicated completion tail pipe.

Several design challenges have been faced to properly centralize the heating cables and clamp the same around the completion tail pipe due to the well size constraints.
Experimental Optimization of Catalytic Process In-Situ for Heavy Oil and Bitumen Upgrading
Authors: Shah A. , Fishwick R. P. , Leeke G. A. , Wood J. , Rigby S. P. , Greaves M.
Published: February 2011

The worldwide conventional crude oil demand is on the rise and because of the rising prices, unconventional oils are becoming more economically attractive to extract and refine. However, technological innovation is needed, if heavier oil supplies are to be further exploited. Toe-to-heel air injection (THAI), and its catalytic add-on (CAPRI) processes combine in-situ combustion with catalytic upgrading using an annular catalyst packed around the horizontal producer well. These techniques offer potentially higher recovery levels and lower environmental impact than alternative technologies, such as steam-based techniques. An experimental study is reported concerning the optimization of catalyst type and operating conditions for use in the THAI-CAPRI process. Experiments were carried out using microreactors containing 10 g catalyst, with oil flow of 1 ml.min−1 and gas flow of 0.51.min−1, under different temperatures, pressures and gas environments. Catalysts tested included alumina supported CoMo, NiMo and ZnO/CuO. It was found that there was a trade off in operation temperature between upgrading performance and catalyst lifetime. At a pressure of 20 bar, operation at 500 °C led to an average of 6.1 °API upgrading of THAI oil to 18.9 °API, but catalyst lifetime was limited to 1.5 hours. Operation at 420 °C was found to be a suitable compromise, with upgrading by an average of 1.6 °API, and sometimes up to 3 °API, with catalyst lifetime extended to 77.5 hours. Coke deposition occurred within the first few hours of the reaction, such that the catalyst pore space became blocked. However, upgrading continued, suggesting that thermal reactions or reactions catalysed by hydrogen transfer from the coke itself play a part in the upgrading reaction mechanism. The CAPRI process was relatively insensitive to changes in reaction gas medium, gas flow rate and pressure, suggesting that the dissolution of hydrogen or methane from the gas phase does not play a key role in the upgrading reactions. By careful control of the temperature and oil flow rate in the in-situ CAPRI process, additional upgrading compared with the THAI process alone may be effected, resulting in a more valuable produced oil, which is easier to transport.
Evaluation of Stimulation Techniques Using Microseismic Mapping in the Eagle Ford Shale
Authors: Inamdar A. , Malpani R. , Atwood K. , Brook K. , Erwemi A. , Ogundare T. , Purcell D.
Published: February 2011

The main goal in stimulating shale formations is to maximize the reservoir contact with the hydraulic fracture face. In order to achieve this goal current practices include pumping low-viscosity fluids at high rates with small mesh proppant cycles. A novel approach was used in a well in the Eagle Ford shale to enhance the stimulated area. This technique, called “relax-a-frac”, was developed by an operator/service company alliance during the exploration phase. Real-time microseismic hydraulic fracture monitoring (RT HFM) indicated that the conventional slickwater treatments were not providing adequate lateral coverage across the planned stage. To address this issue, controlled changes were made to the pumping schedule, and the effects were evaluated using RT HFM. The results indicated that relax-a-frac proved to be highly successful in increasing the estimated stimulated volume (ESV) in this formation and area.

In relax-a-frac, a part of the stimulation treatment was pumped (usually pad plus proppant slugs), followed by an extended shutdown to relax the formation. Once the surface pressure reached a predetermined value, the treatment was resumed, as per program, with monitoring for microseismic activity. The microseismic activity observed during the second part of the treatment showed a significant increase compared to that of the first part, with improved lateral coverage. The resultant ESV increased significantly from this technique as compared to any other specific changes tried on these wells. Production log results from Well 1 showed a definitive correlation between production contribution and the ESV derived from HFM analysis. This paper documents that this novel approach more effectively stimulates the Eagle Ford shale when compared to the typical treatment designs. Conclusions from a detailed comparison of the well performance and its relation to the treatment design are included.
Continual Bit Design Evolution Improves Performance in the Skinner Ridge Field - Piceance Basin
Authors: Garza Travis , Wimberg James , Kopp Kevin , Cheatheam David , Hettinger Gary , Pantuso Chaunsey
Published: February 2011

The Piceance Basin is one of several unconventional gas resources that have been the subject of intense industry activity throughout onshore North America. Due to challenged Rocky Mountain natural gas prices and a recent high cost environment, drilling and completing wells quickly and inexpensively is crucial to managing the economic conditions in Chevron’s Skinner Ridge Field development in western Colorado.

A focused effort on continual improvement has been employed by the Chevron Piceance Drilling Team to maximize drilling efficiency. In terms of drilling performance, an obvious method to reduce drilling time and cost is to physically drill faster by achieving increased drill bit rate of penetration (ROP) without compromising bit reliability.

The following paper summarizes performance improvements achieved through numerous bits trials, dull bit grading analyses and design iterations through a process of application design engineering at the supplier/customer interface. The result has been a step change in drill bit performance exhibited by the continual increase in average 7-7/8 inch bit ROP: from 45 ft/hr during the initial delineation program to 184 ft/hr on the most recent development well pad. Based on this demonstrated performance, the bit designs and cutter technologies have been transferred to other operations, showing that the application of this design approach provides practical means of maximizing efficiency.
Preliminary Assessment of Oil-Rim Reservoirs: A Review of Current Practices and Formulation of New Concepts
Authors: Lawal Kazeem A. , Wells Inewari A. , Adenuga Ademola O.
Published: February 2011

Where oil is the primary target, undesirable production of gas and water complicates the exploitation, management and performance evaluation of thin oil reservoirs. Conventionally, either as a precursor or benchmarking tool for relatively expensive simulation studies, zero-dimensional first-pass models are employed to evaluate performance.

This paper reviews some common models for conducting preliminary assessment of oil-rim reservoirs. The models, diverse in underlying concepts and functional forms, are Osoro et al. (2005), Wyne et al. (2005), Kabir et al. (2004), Vo et al. (2004), and Irrgang (1994). By highlighting their relative strengths and weaknesses, they are shown to be generally inconsistent, inherently limited in scope of applicability, and could yield non-physical results. Consequently, they are not robust as screening and validation tools. The main explanation for the non-robustness of these empirical and simulation-based correlations is that they do not capture the key physics of oil-rim reservoirs. Hence, a different approach is imperative.

In sharp departure from current practices, an integrated energy-balance approach is introduced. In principle, the energy potential of the reservoir establishes the upper bounds of hydrocarbon recovery. For a system under gas-cap drive, an expression for the theoretical limits of reservoir energy is derived, showing that the primary controls of reservoir potential are initial reservoir pressure and volume of gas-cap. Further developments of the proposed concept would focus on deriving expressions for the demand-side of the energy balance.
Solutions to the Down Hole Vibrations During Drilling
Authors: Yaveri Mokhtar , Damani Karan , Kalbhor Harshad
Published: February 2011

The drilling of a well is a dynamic process hence vibrations are inevitable. Drill string vibration induces premature wear and damage to the drilling equipment which results in fatigue failures. Not only will this increase the overall drilling time but also incur huge losses in the form of MWD tools failure and down-hole tools failure affecting the economics of the project. This is neither feasible to the operator nor to the service provider.

It has become necessary for the drilling industry to come up with solutions which can mitigate the problem of drilling dynamics. To understand drilling dynamics in detail we performed a case study on 16 offshore wells. The case study focuses on the vibration problems encountered in the 8.5" section of the 16 wells. We tried to evaluate the reason for the vibrations occurring such as stick slip & lateral vibrations and studied the intensity at which it was occurring. The solutions we have proposed can find tremendous applications in the industry to control and reduce down hole vibrations.

The ability to monitor and correctly interpret dynamic drilling behaviour depends on background knowledge of vibration problems and how they occur. Appropriate corrective action can have a significant impact on MWD tool life, drill-string life, motor life, bit life, drill rates, and drilling efficiency. The work presented here will give solutions which can be used to reduce drill string vibrations and help the economics of the project. Based on our study on the 16 wells, we derived conclusions and have come up with a few actions in the form of a ‘Ten Point Plan’ that can help mitigate vibrations.
Appropriate Gas Price Determination in the Emerging Nigerian Gas Market
Authors: Akinpelu L. O. , Iwayemi A. P.
Published: February 2011

The key challenge of Gas Pricing in the Nigerian Environment is the need to balance three seemingly conflicting objectives: Maintaining the required level of Gas Supplies to support Domestic Economic GrowthProviding Producers with sufficient incentives to continue to invest in Exploration & Development of New Gas Reserves andMaximizing Revenue from Exports

At the current level of development of the Gas Industry in Country, the fundamental question of how to achieve economic pricing as the industry transits from a monopolistic market structure characterized by administered prices to a competitive structure, based on a market determined pricing mechanism will have to be addressed.

We present a simple model to determine the appropriate price of Gas to be paid at the wellhead. The Model focuses the different End Users towards the ultimate price – Opportunity Cost pricing as proxied by the netback Gas Export Price or Export Parity Pricing (EPP). There will be a Transition period to full Market Pricing – determined by how quickly the Market develops.

A Scalar factor is used to achieve the level of support deemed appropriate for the different sectors identified in the Gas Master Plan: Power, Export LNG and Commercial Sectors during the transition period. The Scalar factor will be a fraction during the transition period and reach a value of 1.0 at the end of period (or Sector Pricing will equal Export Parity Price). The magnitude of the Scalar factor and its rate of change will reflect a combination of Policy Objectives and Market Responsiveness thereby ensuring the needed dynamism into the Pricing Model.
Nigerian Gas Masterplan and Policy: Is It a Constrained Energy Policy?
Authors: Onyeukwu Humphrey
Published: February 2011

The Nigerian Gas policy is been aligned to maximise the oil and gas sector value to the economy and transit from an oil industry to an integrated oil and gas industry. These initiatives have been geared towards boosting the domestic market and realize maximum revenue possible from gas. As a result, the gas policy framework in Nigeria has been undergoing series of reforms and new policy initiatives and these have initiated the Gas Master Plan, namely: the Domestic Gas Supply Obligation, the Gas Pricing Framework and the Gas Infrastructure Blueprint.

In the light of the interplay of political and economic factors in Nigeria, the paper examines the strength of the Nigerian Gas Master Plan and Policy to unlock the potentials of a viable Nigerian domestic gas market and discusses to what extent is the Policy constrained. The paper shall identify the magnitude of these constraining factors and would seek to answer the question in view of the stated objective of the Nigerian Government to position the domestic market on a sustainable growth path and leveraging gas for the economic growth of the country.
Modeling of Hydrate Dissociation in Subsea Natural Gas Production Flowlines
Authors: Osokogwu U. , Ajienka J. A.
Published: February 2011

Gas hydrate is one of the major challenges facing production and transportation of natural gas from the remote regions of deep waters, ultra-deep waters and the arctic areas where large reserves have been discovered globally. Gas hydrate is grouped into three types; type I, II and H. Among the aforementioned types, type II is of interest to the oil and gas industry because this is the one that obstructs natural gas flow in production pipelines. In dissociating hydrate in a production pipeline, the following techniques are applied; thermal, chemical, depressurization and mechanical. However, depressurization technique is the most widely used in field of operations where absolute hydrate plugs in production pipelines are experienced. This method has been applied from time past with rule-of-thumb as there are limited models on hydrate dissociation. In this study, a mathematical model was developed based on cubic-degree polynomial using Fourier law. The developed model considered a radial dissociation from a two-sided approach on a fixed boundary which was finally programmed into software called PIPECLEAN using Visual Basic(as shown in Fig 7 and 8) and validated with published experimental data. Results show that dissociation commences from a temperature of 285.7K and above 13hours to dissociate a production flowline that is plugged off by gas hydrate. The study will aid depressurization operations in the field to predict hydrate dissociation real-time, the dissociating temperature to achieve this and the hydrate penetration depth inwardly from the walls of a pipeline. More importantly, the developed model will assist in curbing the problem of guesses when dissociating hydrate in field of operations. One limitation is that the model cannot determine gas evolved during dissociation.
Well and Reservoir Parameters Estimation (K and Skin) Using the Statistical Diagnostic Approach....Part II
Authors: Biu Victor T. , Biu Emmanuel O. , Buduka Stanley , Ajienka Joseph , Onyekonwu Mike
Published: February 2011

In pressure transient analysis, the derivative, typecurve and semi-log pressure curve is used to estimate wellbore and reservoir parameters. How accurate are this figures which solely depend on the extent of the transient period as interpreted by the derivative plot considered for reservoir characterization. Though this approach is universally accepted by welltest analysts, reservoir engineers and the academia in the oil and gas industry but the possibility of over or under estimating wellbore and reservoir parameter is not in doubt, hence there is need to checkmate such interpretation using alternative approach

This paper focus on permeability and skin estimation using the statistical approach to checkmate the quantitative interpretation of the derivative method. Part 1 of this work focus on flow regime identification using the statistical method.

Result from channel sand, low and high permeability reservoir, infinite acting and closed boundary indicates that the estimated permeability for both approach is much closed. Maximum difference of about 13% is notice in closed boundary model while the minimum difference is about 1% in infinite acting reservoir response. Generally, the best match for K and S estimate is seen in channel sand and high K, acidized model. Also in all cases considered, lower slope is obtained from the Statdev approach which is responsible for lower estimated permeability. Invariably the Statdev depict larger extent of transient flow regime as compare with the derivative, making it applicable even where data whose fingerprint for the transient period are insufficient for the analysis.
Optimization of Gas Condensate Reservoir Using Compositional Reservoir Simulator
Authors: Udosen Emmanuel O. , Ahiaba Okpanachi O. , Aderemi Samuel B.
Published: February 2011

In the past years several authors have fielded many questions from companies, both domestic and international concerning gas condensate reservoirs. It appears that gas condensates are becoming more important throughout the world. Also, many international petroleum societies are beginning to have conferences specifically oriented to gas condensate reservoirs and discussing all parameters germane to such systems. Based on this increased interest, we took up the challenge to study gas condensate reservoir, and in this paper we have highlighted the best production method and future exploitation plans for a gas condensate reservoir using a compositional simulator to justify the application of WAG, pressure depletion and gas cycling technique aimed for optimum reservoir and production performance. The results show a remarkable improvement of condensate recovery after an optimization job was done for different scenario. Also, this paper emphasize on a major associated problem with producing gas condensate reservoir, which is the effect of retrograde condensation that results to condensate (blockage) banking, thus causing a reduction in reservoir and well performance.
Bubblepoint Pressure Correlations for Niger Delta Crude Oils
Authors: Okoduwa I. G. , Ikiensikimama S. S.
Published: February 2011

Knowledge of bubble point pressure is very important in reserve estimation and other petroleum engineering calculations such as modeling of fluid flow through porous media and multiphase flow in pipe. When laboratory PVT analysis is not readily available, empirical PVT correlations becomes the best alternative. In this study, correlations for bubble point pressure for Niger Delta crude oils were developed using non-linear multiple regression. This was done by categorizing Niger Delta crude oil into five oil API gravity ranges (API≤21, 21<API ≤ 26, 26<API ≤ 35, 3545). Different correlation models were developed for each oil API gravity range. Different quantitative and qualitative approaches were used to compare the new correlations with other published correlations. The results of all the correlations show that better correlations were obtained when the crude are categorized into oil API gravity ranges. For Niger Delta Crude Oil, the new correlations developed by this study performed better than existing published bubble point pressure correlations.
NMR-Openhole Log Integration: Making the Most of NMR Data Deliverables
Authors: Ehigie S. O.
Published: February 2011

The benefits of NMR data integration as a technique for improving conventional openhole log evaluation are already appreciated by many practitioners. Two pathways for achieving this integration are (1.) using NMR data to refine input parameters for conventional log analysis (sometimes in-lieu of core data) and (2.) using certain NMR-based analyses to constrain the results emanating from openhole log analysis.

However, in practice, a key factor to the slow take-up of NMR-openhole log integration techniques (in addition to a generally limited appreciation of the techniques themselves) remain in the disparate NMR data delivery formats among the service providers. Essentially, it is fair to say that NMR data delivery has yet attained the same level of standardisation that has already been witnessed in conventional openhole logging. For example, the NMR acquisition dataset from the major service providers are not strictly equivalent, and consequently often require different manipulation and interpretation strategies. This state of affairs also means that an integrated NMR-openhole log interpretation procedure may be difficult to transfer, in a consistent way, between acquisition datasets from different service providers.

Furthermore, unless specific data requests are communicated prior to NMR log acquisition, most service providers will deliver only a partial dataset of the acquisition, at best. Bearing in mind that logging contractors do not generally retain their clients' data indefinitely, maximizing the value of originally-delivered NMR log data may often become the only possible objective many years after their acquisition.

The focus of this paper, therefore, is discuss how NMR data are delivered by the different logging companies and to recommend NMR-openhole log integration techniques for making the most of a variety of NMR data, as may have been originally delivered by the different service providers.
Evaluating the Impact of Fiscal Provisions in the Draft Petroleum Industry Bill on Offshore E&P Economics and Take Statistics in Nigeria
Authors: Iledare Omowumi O.
Published: February 2011

The structure and conduct of the global E&P industry have changed significantly over the years; to the extent that the search for and development of petroleum resources have become mostly driven by the attractiveness of fiscal regimes rather than geological prospectivity only. A dynamic and stable fiscal arrangement must now include contract terms and instruments that will willingly give up an appropriate proportion of economic rents to investors to guarantee sustainable capital investment flow for resource development. A high exploration risk and low prospective region must balance government takes with an attractive rate of return on investment. Of course, where exploration risks are low and geological prospects are high, the host government can be expected to want to capture a high economic rent per unit of hydrocarbon production. This paper reviews the economics of offshore petroleum exploration and production (E&P) operations within the context of the ensuing petroleum industry institutional restructuring and reforms in Nigeria. The paper provides a careful review of the fiscal terms and instruments in the draft petroleum industry bill (PIB) and the effects on the economic measures and government take statistics of an archetypal deepwater oil and gas venture in offshore Nigeria.
Modeling of Cement Thickening Time at High Temperatures With Different Retarder Concentrations
Authors: Umeokafor C. V. , Joel O. F.
Published: February 2011

Primary cementing is the process of placing cement between the casing and borehole in a well. The main objectives of primary cementing are to seal the annulus and to obtain zonal isolation. For zonal isolation to be achieved, all drill cuttings and drilling fluid must be removed from the annulus and replaced by cement slurry. Cement slurry must then undergo hydration, changing from the liquid to the solid phase and developing properties to prevent flow of formation fluids and to support the casing. The cement sheath should also be able to withstand different operations such as stimulation, perforation, production, and intervention during the life of the well. Adequate thickening times are required for a good cement job.

Study was made with 36 thickening time test results carried out for a 5 inch high temperature liner cementing jobs done in the past at temperature range of 230°F to 284°F for different retarder concentrations. Thickening time plots for the retarded cement slurry was obtained for the temperature range investigated. Model which predicts thickening time at the specified retarder concentrations and temperatures was developed. The model equation at the different temperatures and retarder concentrations is given by: Y = 32.53882954 − 0.15380761X1 + 12.10530547X2 + 29.80930457X3.

Thickening times predicted showed good agreement with experimental values with less than 10% deviation. The model equation developed will help predict the thickening time at the various retarder concentrations and temperatures and thereby help in saving time and cost associated with the rigour in actual laboratory experimental recipe design and testing.