bluuebunny/crossref_metadata_2025 huggingface dataset:
Case Study: Lennox—The Race to Produce Oil Prior To Gas Cap Blowdown
Authors: Clarke A. , Ayton J. , Lawton D. , Lean J. , Burke K.
Published: December 2007

Ten years since production commenced from the Lennox Field and one year from the start of full gas cap blowdown, the challenge to produce oil from the Lennox oil rim has never been greater. The Lennox Field is one of six fields comprising the Liverpool Bay Development located in the UKCS, East Irish Sea. The Lennox oil rim is at a critical stage in the development of the asset as it transitions from an oil field to a gas field. The field was initially developed with horizontal and multi-lateral wells placed to maximise oil reserves and minimise movement of the gas-oil and oil-water contacts with re-injection of all produced gas to maintain reservoir pressure. Since other sources of gas in the area commenced their decline, Lennox must now sustain plateau nominated gas sales and as a result there is little time left to recover the remaining oil.

In a first for the development, a dual lateral well (110/15a-L13/L13z) was drilled in mid 2005 as a sidetrack to a poorly performing single bore well and completed with an intelligent completion to supply gas lift gas from the gas cap. The intelligent completion will assist the well to flow, maximise oil recovery and eventually allow a simple conversion to a gas well. The well was a success with better than expected reservoir intersections and the initial oil rate exceeding predictions. The project, initially designed to address unswept oil in the Lennox Field, was expanded to apply the artificial lift technology used at L13 to mature Lennox wells to allow continuous lift at higher watercuts and lower reservoir pressure. The result has highlighted the need to continually re-evaluate opportunities and challenge existing development plans and assumptions.
In-Situ Stresses Evaluation Using Well and Field Data: Integrated Methodology Approach
Authors: Pellegrino A. , Cappanera F. , Toscano C.
Published: December 2007

In the present paper we describe the workflow followed to estimate the field state of stress (FSS) for a well stimulation design in a faulted field. The customer demand was about the fracture gradients along the well-bore trajectories and about the fracture paths. To satisfy the customer demand an integrated study was performed using field data and well-bores evidences. On the base of available information a numerical model has been used that allows taking into account the complex geometry of the faults. The different FSS have been applied to three well-bores and the obtained break-outs have been compared to the observed ones. Two example of FSS, the worst and the best one, are illustrated and compared.
Wettability Alteration for Water-Block Prevention in High-Temperature Gas Wells
Authors: Panga M. K. R. , Ooi Y. S. , Koh P. L. , Chan K. S. , Enkababian P. , Chenevière P. , Samuel M.
Published: December 2007

This paper presents the development of a chemical system for water-block prevention in gas/condensate wells. The chemical system alters the formation wettability to intermediate gas wet conditions thereby decreasing the capillary forces and enhancing the clean up of trapped water at low drawdown pressures. Five different chemicals (A1-A5) are evaluated in this study for their ability to prevent water block formation at high temperature. Adsorption/desorption characteristics of these chemicals and temperature stability are also investigated for long-term prevention of water blocks. Contact angle and air-brine imbibition tests are conducted to determine wettability alteration before and after treatment with the chemicals. The results show that chemical A5 gives the best wettability alteration at high temperature with minimum formation damage. The improvement in water block removal after treatment with A5 is tested by injecting gas into brine-saturated cores at different pressure gradients and measuring volume of displaced brine. Higher volumes of brine clean up and lower flow initiation pressure gradient are observed after the treatment.
Techniques for Optimum Placement of Interval Control Valve(s) in an Intelligent Well
Authors: Ebadi F. , Davies D. R.
Published: December 2007

Intelligent Well (IW) Technology improves well and field performance management by combining zonal production control using Interval Control Valves (ICVs) with the installation of flow monitoring devices. The "Added Value" for an IW is dependent on the number and location of the ICV controlled zones. Too many valves lead to unnecessary and excessive cost as well as the potential for reduced reliability. Too few valves will not provide sufficient flexibility for efficient control.

We previously showed 1 that a minimum degree of un-even fluid-front progression needs to be induced in order for effective ICV control to be observed to "Add" sufficient "Value" to justify the costs and risks involved in installing this relatively new technology. ICV(s) can balance the fluid-front provided they are placed correctly. A typical example would be their installation across zones showing early water or gas break-though. This allows "Value" being "Added" to the reservoir management process by controlling the unwanted fluid. Optimum ICV placement requires prediction of these zones. The extent of reservoir layer / zone connection thus needs to be quantified. In practice, the available information is often limited to (local) information gained from measurement at or very near the wellbore during the drilling of the well, together with exploration seismic and (global) reservoir geological studies.

A systematic study of the "Added ICV Value" for a range of reservoir models has been completed. The number of ICVs installed and the zonal length were varied. Emphasis was given to studying the more complex (e.g. channelised) reservoir models where prediction of the extent of reservoir layer / zone connection is more difficult.

This study provides optimum ICV placement guidelines for different well and reservoir geometries with a variety of reservoir drive mechanisms. Results from this study highlight the importance of correct ICV placement. The results can be used as a screening and decision making tool for deciding on the optimum number of the ICV(s) and their placement.
Permeability Modeling in Porous Media: Setting Archie and Carman-Kozeny Right
Authors: Haro Carlos F.
Published: December 2007

Archie's empirical law constitutes the basis of quantitative Petrophysics; however, the physical significance of this law is poorly understood. The issue involves substantial uncertainty in oil in place. Similarly, Carman-Kozeny's (C-K) relation is source of several permeability models. C-K is derived from Poiseuille's equation, applicable in laminar-viscous-flow in straight-uniform non-communicating tubes. Neither C-K nor Poiseuille's formulae consider inertial accelerations, non-Darcy flow, caused by changes in either cross section or flow direction occurring in porous media. Implications include sizeable limitations in permeability modeling.

Suitable hydrodynamic and electrical models can be created using fluid mechanics analytical methods. The models delineate the velocity and electrical potentials, streamlines and controls, represented by C-K and Archie's equations. This approach theoretically verifies both relations and reveals that:

Assisted by the boundary layer theory, fluid circulation and permeability are optimally modeled invoking superposition of viscous and inertial regimes in nozzles, throats, diffusers, pipe networks, and arrays of solid particles. These hydraulic components, once assembled, emulate interconnected pore throats and bodies very well. The flow around a corner solution of Laplace's equation characterizes the changes in fluid and electric flow direction, mainly occurring in the pore bodies. The solution precisely defines rock frame, conductive phase, and hydraulic tortuosities, enabling direct ties to pore geometry. This facilitates permeability calculations utilizing the "perfect permeability transform" procedure.

The aim of this work is to show how Archie's law ceases being merely empirical and C-K becomes thorough, thus gaining a full physical conception of their power law behavior. As a result, revised Archie's and C-K relations are proposed for water saturation and permeability computations. Main applications comprise the generation of rock catalogs and synthetic production logs to assist in history matching.
Possible Alternatives for Gas-Charged Accumulators in Deep Waters
Authors: Amani M. , Rajabi M. Mir , Juvkam-Wold H. C. , Schubert J. J.
Published: December 2007

Gas Charged Accumulators are widely used in Drilling operations. These accumulators are not efficient at all in Deep waters, and there are not many alternatives for them. This paper looks into possible alternatives for Gas Charged Accumulators in Deep Waters.

Supplying enough volume of pressurized hydraulic fluid to operate the BOPs for emergency situations is essential for Deep Water Drilling. This requires storing the pressurized hydraulic fluid in accumulators. A problem may arise when the wellhead is at water depth of more than 3500 ft. In deep water drilling, the accumulators are placed on the subsea BOP stack to reduce hydraulic response times and provide a hydraulic power supply in case of interruption of surface communication. Hydraulic fluid capacity of an accumulator may drop to 15% of its capacity on the surface and even less, depending on the water depth. The reason for this is that the nitrogen gas does not behave like an ideal gas as we go to very deep water, due to high hydrostatic pressure at that water depth.

The possibility of the use of springs and heavy weights as possible replacements for nitrogen in the structure of accumulators will be discussed in this paper. High hydrostatic pressure of deepwater will not affect the functionality of these mechanical accumulators.

Transferring bank of accumulators to the surface and connecting them to the BOP with properly sized and rigid pipes can decrease response time to an acceptable level to satisfy regulations and standards. This idea can be considered as an alternative solution too.

We have to include the hydrostatic pressure of water in the usable fluid calculation. A low pressure tank located on the sea-floor can dismiss the negative effect of high hydrostatic pressure of seawater. This alternative idea is also discussed.

Using a column of high density fluid as the accumulator system is another alternative method that is presented in this paper and should be investigated further for such application.
Case Study: The Application of Inflow Control Devices in the Troll Oil Field
Authors: Henriksen K. H. , Gule E. I. , Augustine J.
Published: December 2007

This paper describes the application of Sand Control Screens coupled with Inflow Control Devices (ICDs) in the Troll Oil sub sea field development. Technical and functional description, qualification, computer modeling and production experience verifies that completions with ICDs yield higher volumetric recovery of oil from each well compared with more conventional sand control completion methods. Improved sand control results from the screen systems inflow distribution functionality.
Advanced Completion Technology Creates a New Reality for Common Oilfield Myths
Authors: Augustine J. , Ratterman E.
Published: December 2007

Several myths have historically permeated the oil industry. These myths typically included: "I can't gain incremental production from a lateral exceeding 1500 ft", "I have to produce my well at the critical coning rate to prevent early water production", and "I have to gravel pack my well to achieve sand control and completion longevity". These myths are being conquered with the generational development and implementation of Inflow Control Technology that allows the wellbore to access and produce larger reserve volumes while eliminating the onset of early water production and/or premature gas breakthrough. Inflow Control Technology enables the prevention of water/gas breakthrough by passively controlling the inflow profile along the length of a well. An increased understanding of wellbore and reservoir fluid dynamics has been achieved through the continued research and application of this technology. To address the diversity of reservoir conditions, this understanding has spawned the integration of state of the art completion and inflow control technology to achieve well specific solutions. Optimum completion solutions should be designed to address the reservoir characteristics. Today, the industry has delivered sand control completions in lateral lengths exceeding 11,000 ft, eliminated water breakthrough in naturally fractured carbonate formations, and provided sand control without gravel packing in formations that would have otherwise required a gravel media. This paper discusses the origin of the historical myths and the case histories leading to the obsolescence of these myths. The global applications reviewed include completion installations in the UK and Norwegian North Sea Sectors, and Saudi Arabia.
Reducing Uncertainty of Reserves Estimates Using Inversion of Time-Lapse Logging Data
Authors: Frenkel M. A.
Published: December 2007

The estimation of hydrocarbon reserves heavily depends on the accuracy of resistivity data and the reliability of their interpretation. To optimize data information extraction from acquired modern array resistivity logs, integrated inversion- based interpretation techniques are required. However, the direct application of an inversion method may provide an incorrect equivalent solution, resulting in erroneous hydrocarbon estimates.

To solve the equivalency problem, we have developed a new method that reconstructs the formation model in steps using inversion of time-lapse Logging-While-Drilling (LWD) and Wireline (WL) measurements. The main steps are: Estimate resistivities of invaded and uncontaminated zones using LWD data focusing or inversion.Re-estimate resistivity of the invaded zone using WL logs, array data focusing or inversion.Estimate depth of invasion using WL data inversion and the results of the steps above.Re-estimate the model parameters using WL data inversion and the results of the steps above.Estimate parameters of a complex invasion radial profile using WL data inversion.

To establish the effectiveness of the method, we tested it on a synthetic example that was constructed using LWD and WL logs acquired in a well from the South China Sea. This field data was also used for our case study.

The conclusion is that the suggested method provides a framework for effective integration of time-lapse logging measurements to increase accuracy of formation evaluation.
Diagnosis of Reservoir Behavior From Measured Pressure/Rate Data
Authors: Kabir C. S. , Izgec B.
Published: December 2007

This paper presents a simple diagnostic tool to identify reservoir flow behavior from a Cartesian pressure/rate graph. Some of the benefits of the proposed tool are its simplicity without requiring any calculations, leading to understanding of reservoir compartmentalization and application of an appropriate material-balance technique.

Data diagnosis entails graphing pressure with rate and discerning trends; positive slope signifies the pseudosteady-state (PSS) flow period, whereas the negative slope implies infinite-acting (IA) flow. Constant-rate production exhibits infinite slope whereas constant-pressure production produces zero slope. Mathematical justifications for these diagnostic signatures are presented. During PSS flow, wells belonging to the same container will exhibit the same slope.

Differences in slope are an indication of reservoir compartmentalization, lateral or vertical. Equally important we provide mathematical proof of why different wells in a multiwell reservoir system should have the same slope. Field examples from multiple gas and gas/condensate systems show how the proposed tool works in practice.
Preventing Naphthenate Stabilised Emulsions and Naphthenate Deposits on Fields Producing Acidic Crude Oils
Authors: Hurtevent C. , Ubbels S.
Published: December 2007

Naphthenic acids in a crude from field A in West Africa in combination with high pH connate waters cause severe problems during the separation of oil and water. The neutralization products of those acids with basic components in the water tend to form very stable water-in-oil emulsions and insoluble sticky naphthenate sludge. These phenomena considerably hamper oil production and result in high treatment costs using acetic acid.

This paper discusses the ways problems were prevented during a large field trial with a combined demulsifier/naphthenate inhibitor based on a physical and chemical approach. Innovative technology in surface-active chemistry has demonstrated an effective way to reduce or eliminate the problems described.

In addition, lab tests were performed on an instrumented bottle test that enables the different phases of decantation (Coalescence, sedimentation, dense emulsion) to be measured. Two conventional demulsifiers used in the field were tested and compared to this new combined demulsifier/naphthenate inhibitor. The new chemical prevented the formation of dense emulsion and resulted in better water quality.

Further experiments demonstrating the unique challenges associated with naphthenates in different fields around the world are also presented.
Selective Removal of Water From Supercritical Natural Gas
Authors: Karimi A. , Abdi M. A
Published: December 2007

The demand for natural gas has pushed energy industries toward the discovery of remote offshore reservoirs. Consequently, new technologies have to be developed to efficiently produce and transport natural gas to consumption centers. Common design challenges in all gas processing methods for offshore applications are the compactness and reliability of process equipment. Water vapour is the most common impurity in natural gas mixtures. At very high gas pressures within the transportation systems hydrate can easily form even at relatively high temperatures. Gas dehydration or hydrate inhibition systems for offshore gas production/processing facilities should meet these requirements. It should also be noted that at certain pressure and composition conditions, the presence of heavy hydrocarbons (C2+) in natural gas increases pipeline flow capacity and improves compression efficiencies. Therefore, the development of a compact high pressure system capable of selectively removing water from high pressure natural gas streams without affecting the hydrocarbon content will be needed for especial applications and therefore it will be addressed in this paper. Most hydrate inhibition/water removal systems can only work below certain pressure conditions, are relatively large, and not selective towards water. Therefore, some hydrocarbon condensate is also removed during water dew pointing. The developed technique proposed in this study can be customized for the emerging marine transportation of gas in CNG form where the removal of heavier hydrocarbons might not be necessary and will be equally suitable for any other offshore/onshore natural gas production and processing including subsea production of oil and gas. This paper concentrates on the development of simulation techniques needed to accurately estimate dehydration efficiency to control hydrate in a supercritical flow using supersonic nozzles.

A simulation model linked to a thermodynamic property generator is needed to predict the water removal efficiency under various flow conditions. The computer simulation results for water removal from a typical offshore natural gas stream under various conditions will be presented and compared with conventional techniques. Intensive water dew points down to about -50 to – 60 °C can be achieved without any cryogenic cooling or use of solid adsorption techniques.
Estimating Percentage of Fracture Fairways Detectible by Seismic Data—Case Studies From Oman
Authors: Ozkaya Sait Ismail , Richard Pascal , Mueller Guy
Published: December 2007

This paper discusses the detection of fluid conductive fracture fairways using seismic data calibrated with BHI or dynamic data. Fault-related fractures display a high degree of clustering at several scales. Fracture cluster within fracture corridors and fracture corridors are clustered within fracture fairways, which are overall equivalent to fault zones.

We compared the location and spacing of fracture fairways from image logs with seismic faults and lineaments and estimated the percentage of fracture fairways that can be detected by seismic attribute maps. Correlation with flow profiles, lost circulation and water breakthrough and productivity index was necessary to determine fraction of fluid conductive seismic faults and fracture corridors from borehole images. The results showed seismic fault maps from one of the two fields detected more than 90 percent of all fracture fairways. The fault map could be effectively used for well planning and simulation and in combination with fracture corridor clustering, density and transmissivity data from borehole image logs and pressure transient analysis. Seismic maps from the other field could detect only half of the fracture fairways and indirect indicators from dynamic data had to be used to identify and map fracture fairways.
Studying the Scaling Mechanism of Low-Permeability Reservoirs Using Visual Real-Sand Micromodel
Authors: Xiaojuan Ren , Pingchang Wu , Zhihao Qu , Chengen Shi
Published: December 2007

Chang 3 reservoir in Hua 152 block is located in the Ordos basin, China. The average permeability and porosity is 3.17mD and 14.9%. There exists serious scaling at the oil layer near to bottom hole because of high salinity formation water and incompatible injection water. The scaling process and mechanisms in the layers has been researched by means of a visual real-sand micro-model. The results have shown that: 1) The permeability of the oil layer will reduce by 40% when formation water contacts with injection water twice times at the same place; 2) It is very easy for scaling molecules to crystallize from water phase and scale particles are very small because the pores and throats of the formation rock contain a lot of fine clay and impurity; 3) The scale accumulates in pores and looks like "chicken roost"; 4) The scale inhibitors can reduce scaling, but the higher concentration of scale inhibitors is needed. Scaling in low permeability reservoirs may significantly reduce rock permeability thus affecting the production of oil well. The visual real-sand micro-model is a good method to use in research of scaling mechanisms because of its visualization, using actual rock and ease of construction.
Field Experiences in the Application of an Inhibitor/Additive Interaction Package to Extend an Inhibitor Squeeze Life
Authors: Chen P. , Hagen T. , Montgomerie H. , Berge T. , Haaland T. , Matheson R. , Sæten J. O. , Vikane O. , Børeng R. , Bjørnestad E. Ø. , Asheim T. I.
Published: December 2007

Since the middle 1980s, seawater breakthrough has been observed for a number of wells in a major offshore Field operated by Statoil. This Field has also several tie-ins. Both sulphate and carbonate scale deposition has been identified in the near well bore area and tubing. Inhibitor squeeze treatments were regularly carried out to prevent wells from damages due to scale precipitation. The conventional phosphonate scale inhibitor (DETA-phosphonate) was often used. Some of the sandstone formations in the oil field are relatively "clean" with very little amount of clay materials i.e. Etive and Tarbert formation. As a result, a relatively short inhibitor squeeze life was seen in these formations after the squeeze treatments with a phosphonate scale inhibitor. Other reservoirs had acceptable squeeze life, but due to environmental requirements a wide set of inhibitors was studied.

In order to reduce the well intervention frequency and extend an inhibitor squeeze life, a method involving a polymer interaction between a polymer scale inhibitor and polymer additive has been developed. In addition to the enhanced adsorption; attributed by the surface charge modification by the adsorption of the positively charged polymer additive on the sandstone surface, the interactions between polymer inhibitor and additive further increase the inhibitor retention in the formation. This polymer interaction approach is different from a conventional precipitation squeeze where calcium chloride was used. Also, unlike the conventional precipitation squeeze, the polymer additive can be pre-injected and rapidly adsorbed onto a rock surface. The subsequently injected inhibitor will react with the additive on the rock surfaces, resulting in a precipitation on a rock surface. This avoids the bulk precipitations where a permeability reduction was often caused by a conventional precipitation squeeze. During the production, the precipitated polymer inhibitor was released through a hydrolysis process.

This paper presents a detailed method and field results based on the treatments using the polymer inhibitor and additive package in the oil field. The application of polymer interaction package significantly improved the inhibitor squeeze life. Satisfactory results have been achieved from the field trials. The unique polymer reaction package satisfies the stringent Norwegian environmental regulations of low toxicity, high biodegradation and low bioaccumulation.
Design of Low-Sulfate Seawater Injection Based Upon Kinetic Limits
Authors: McElhiney J. E. , Tomson M. B. , Kan A. T.
Published: December 2007

Reliance on low sulphate seawater as sole protection against sulphate scale may be discomforting to some operators when such expensive subsea wells are at stake. Normal methods such as bullheading squeeze chemicals are nearly impossible to implement due to the long and sometimes multiple flow lines connecting injection wells. Subsea intervention to place squeeze inhibitors is prohibitively expensive due to the requirement of utilizing a service boat over the well for many days.1 Calculations of scaling index from formation and injected seawater mixtures are routinely based upon the thermodynamics of the mixed brines. Although some mixing does occur in the interwell distance, the most vigorous mixing occurs in the vicinity of the production wellbore where water from multiple layers and streamlines impinge. These near wellbore mixtures have short residence times before being produced therefore reaction kinetics must be considered, and it is not clear how low the sulphate concentration in injected water needs to be to delay scaling downhole. This work offers a fresh look at this scaling problem by examining the kinetics of the mixed brines. Using data from existing field projects that currently inject desulphated seawater, the induction times required for non-scaling fluid transit up production wellbores are chosen, and the sulphate concentrations necessary to provide these induction times are computed from a software program.2 The software algorithms are based on a broad, robust database of barite kinetics that span large variations in sulphate and barium concentrations, temperatures and salinities.3 This protocol is compared to scaling index results computed from a thermodynamic approach at both bottomhole and wellhead conditions. A tandem role in which inhibitors can be utilized in conjunction with low sulphate seawater is described.
Mechanistic Understanding of Rock/Phosphonate Interactions and the Effect of Metal Ions on Inhibitor Retention
Authors: Tomson M. B. , Kan A. T. , Fu G. , Shen D. , Nasr-El-Din H. A. , Al-Saiari H. , Al-Thubaiti M.
Published: December 2007

This paper discusses the effects of Ca2+, Mg2+, and Fe2+ on inhibitor retention and release. Better understanding of phosphonate reactions during inhibitor squeeze treatments has direct implication on how to design and improve scale inhibitor squeeze treatments for optimum scale control. Putting various amounts of metal ions in the inhibitor pill adds another degree of freedom in squeeze design, especially in controlling return concentrations and squeeze life.

Phosphonate reactions during squeeze treatments involve a series of self-regulating reactions with calcite and other minerals. However, excess calcite does not improve the retention of phosphonate due to the surface poisoning effect of Ca2+. The squeeze can be designed so that maximum squeeze life is achieved by forming a low solubility phase in the formation. Addition of Ca2+, Mg2+, and Fe2+ in the pill solution at 0.1 to 1 molar ratios significantly improves the retention of phosphonate. Alternatively, these metal ions can be dissolved from the formation while an acidic inhibitor pill is in contact with the formation minerals. Both BHPMP and DTPMP returns were significantly extended by the addition of metal ions, e.g. Ca2+ and Fe2+. The addition of Mg2+ may increase the long-term return concentration, which is important for some wells where a higher inhibitor return concentration is needed.

The laboratory squeeze simulations were compared to two field return data obtained from squeeze treatments performed on two wells located in a sandstone reservoir in Saudi Arabia. The sandstone formation contains significant amounts of ironbearing minerals.
Scale Inhibitor Core Floods in Carbonate Cores: Chemical Interactions and Modelling
Authors: Baraka-Lokmane S. , Sorbie K. S.
Published: December 2007

In previous work (SPE 87447), the effect of pH on phosphonate/carbonate interaction was studied by performing variable pH core floods in short outcrop carbonate cores. Effluent concentrations of scale inhibitor (DETPMP), lithium tracer, calcium and magnesium were measured, as were the corresponding pH profiles. Such detailed sets of measurements are required to interpret the inhibitor/carbonate interaction mechanisms. This previous study showed that carbonate dissolution was evident in all core floods and on how this depended on pH. It also indicated where simple adsorption isotherms could describe this accurately and where this was not the case. Recently, we have performed additional core floods using carbonate core from a second block of this outcrop chalk using DETPMP scale inhibitor slugs at various concentrations and pH values. These results significantly extend previous work and are presented under the following two headings:

Scale inhibitor/carbonate/pH interactions in short cores + modelling: Simple flooding cycles are described on the propagation of (Li traced) slugs of pH 6, 4, and 2 (no scale inhibitor) travelling through the carbonate core in order to study the behaviour of calcium, magnesium and effluent pH for various injected brine pH conditions. These results have been modelled and explained using the MultiScale software.

"Contained" scale inhibitor floods in long (12") carbonate cores: Contrasting floods using long (12") carbonate cores have been performed where <1 PV of DETPMP is injected at the inlet and then back produced. In these floods, the core is never fully saturated and these floods are referred to as "contained" core floods [1]. Very extensive data on SI, cation (Ca, Mg and Li) and pH effluents are collected. These observations lead us to a number of conclusions on the factors that must be included in a full carbonate model. In particular, our experimental results – along with some simple modeling – greatly clarify the role of both calcium and magnesium in the mechanism SI retention in carbonate systems.
Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System Enables Commercial Production From Bypassed Pay in the Olmos Formation of South Texas
Authors: Semmelbeck M. E. , Deupree W. E. , von Plonski J. K. , Mueller F. A. , Chen Y. , Lewis J. W. , Keto L. K. , Fairhurst D. L. , Pope T. L.
Published: December 2007

A novel carbon dioxide- (CO2-) emulsified viscoelastic surfactant (VES) fluid system has recently been used to improve the Olmos production in the Caterina SW field in Texas. The reservoir is characterized by thin streaks of pay with potential water production in close proximity. Due to the low permeability and formation rock properties, CO2-type fracture fluids have proven to be more effective. VES-CO2 was selected as the fracturing fluid because of its higher retained proppant pack permeability and controllable rheological behavior. These unique fluid characteristics resulted in a high-conductivity fracture and a geometry that stayed out of the water-bearing zones. The outcome from 11 treatments resulted in an average production of > 430 Mscf/D and 82 BOPD in zones that were previously bypassed. The successful field applications of this new fluid system highlight the versatility of VES surfactant fluids in terms of rheological property and adaptability. Specific performance requirements can be met through modifying the functionalities of the surfactants, namely, utilizing surfactants with different functions to emulsify super-critical CO2 and still maintain all of the attributes normally associated with VES systems. VES fracturing fluid systems exhibit lower friction pressure, superior proppant transport, higher fracture conductivity and longer effective fracture half-length than conventional systems by completely eliminating polymer. Coupling the benefits of polymer-free VES fluid with a CO2-emulsified system further enhances cleanup of depleted reservoirs, extends the application to water-sensitive formations, and maintains reservoir gas saturation to prevent any potential water blocks.
Improving the Gas and Condensate Relative Permeability Using Chemical Treatments
Authors: Kumar V. , Pope G. A. , Sharma M. M.
Published: December 2007

Production from gas-condensate reservoirs having a bottom hole flowing pressure below the dewpoint pressure results in an accumulation of condensate near the wells causing a large decrease in both the gas and condensate relative permeability. Several methods such as hydraulic fracturing and solvents have been proposed to restore production rates but all of these methods have limitations or they are only effective for short periods of time. We have evaluated new surfactants using a methanol-water mixture as the solvent to treat cores under reservoir conditions. The surfactants have been tested under reservoir conditions using a variety of cores and found to be promising since they significantly increased the steady state relative permeability. Experiments were performed to evaluate the effectiveness of these surfactants at high temperature and high gas flow rates over a range of capillary numbers on the order of those near production wells. The productivity index for sandstone cores was improved by a factor of 2 to 3 for temperatures over the temperature range of 145 to 275 °F for the Novec FC 4430 polymeric surfactant in the methanol-water mixture. These treatments have the potential to greatly increase production at low cost since only the near well region of the reservoir blocked by the condensate needs to be treated.
Simulation Study on Injection of CO2-Microemulsion for Methane Recovery From Gas-Hydrate Reservoirs
Authors: Phale H. A. , Zhu T. , White M. D. , McGrail B. P.
Published: December 2007

Gas-hydrates are crystalline substances composed of water and gas, mainly methane, in which a solid water lattice accommodates gas molecules in a cage like structure. Large methane-gas hydrate reservoirs have been found on the North Slope of Alaska that can be exploited as a future energy source. Depressurization, thermal stimulation, and inhibitor injection are the methods being evaluated for commercial production of natural gas from hydrate-bearing geologic formations.

An alternative method of gas hydrate production using CO2 is under investigation. This process conducts injection of CO2 in the form of microemulsion. This concept has several attractive features: 1) CO2 is thermodynamically favored over CH4 in hydrate, 2) the heat released by formation of CO2 hydrate is 20% greater than the heat needed for dissociation of CH4 hydrate, 3) refilling pore space with CO2 hydrate is expected to maintain mechanical stability of the hydrate-bearing formations during production, and 4) the process is environmental friendly, removing CO2 from the atmosphere while simultaneously producing clean-burning natural gas. This study focuses on the evaluation of a set of optimum parameters for methane recovery with simultaneous CO2 sequestration using the STOMP-HYD simulator. Series of simulations are being carried out to verify the effect of pressure, temperature, CO2-microemulsion injection rate, and the concentration of injected CO2-microemulsion on methane hydrate dissociation. Preliminary, 1-D simulations show that injection of CO2-microemulsion produces considerably more amount of methane than warm water injection alone. These results have also demonstrated that injection of liquid CO2-microemulsion helps in early and significant methane production as compared to the injection of vapor CO2-microemulsion. Initial modeling work supports the novel idea of using CO2-microemulsion for Enhanced Gas Hydrate Recovery.
A Study of Fracture Initiation Pressures in Cemented Cased-Hole Wells Without Perforations
Authors: Rytlewski G. L. , Cook J. M.
Published: December 2007

A new method of completing multiple-layer tight gas wells is being investigated. The main concept is to place sliding sleeve valves in the casing string and complete the well with normal cementing operations. The sliding sleeves would then be opened one at a time to fracture layers independently without perforating. The possibility of high fracture initiation pressures is identified as the main risk with this approach.

This paper will discuss the theoretical and experimental study that was conducted to assess the viability of the cemented sliding sleeve concept by attempting to minimize and predict fracture initiation pressures.

Finite Element Analysis (FEA) was conducted to estimate the stresses in the cement and formation near the wellbore with sliding sleeve. FEA was used to adjust valve parameters that increased tensile stress in the cement and formation. Unstressed cement tests were then conducted on a variety of sliding sleeve valve shapes to verify the FEA study and to select the best valve shape.

Openhole and perforated casing fracture initiation pressures were calculated as a function of rock properties and far field stresses on the rock. An openhole condition was considered the best approximation to the opened sliding sleeve valve in regards to fracture initiation.

Full-scale stress frame tests were conducted using sandstone blocks with far field stress applied. The base case was set up using 4-1/2-in diameter casing cemented in one block and then perforated in the preferred fracture plane. Another sandstone block had a sliding sleeve valve cemented in place. Water was used to fracture these blocks and the fracture initiation pressures were measured. Good agreement between predictions and measurements was obtained, and the results indicated that high fracture initiation pressure is unlikely to be an issue with this completion method.
Well Testing of Tight Gas Reservoirs
Authors: Garcia J. P. , Pooladi-Darvish M. , Brunner F. , Santo M. , Mattar L.
Published: December 2007

Advances in technology, strong energy prices and declining reserves in conventional gas reservoirs are encouraging oil and gas companies to consider the feasibility of exploiting large reserves trapped in tight (low permeability) gas reservoirs.

Conventional well tests conducted on these low permeability gas formations, generally result in poor estimates of key reservoir parameters such as: initial reservoir pressure, permeability, effective fracture length, fracture conductivity, and deliverability potential.

The objective of this paper is to review the different types of tests that are particularly applicable to tight gas formations, discuss why the traditional methods of testing and analysis rarely succeed, and identify appropriate test and analysis procedures for tight gas reservoirs.

We will consider short-term tests where the primary objective is to obtain the initial reservoir pressure, with a secondary objective of determining permeability and skin. Perforation Inflow Tests, Fracture-Calibration Tests, and Formation Flow Tests will be considered. The applicability of these tests will be shown using synthetic and actual field cases.
Constant-Rate Drawdown Solutions Derived for Multiple Arbitrarily Oriented Uniform-Flux, Infinite-Conductivity, or Finite-Conductivity Fractures in an Infinite-Slab Reservoir
Authors: Craig D. P. , Blasingame T. A.
Published: December 2007

A new analytical pressure transient solution (constant rate) for a well containing multiple arbitrarily-oriented uniform-flux, infinite-conductivity, or finite-conductivity fractures in an infinite-slab reservoir is presented. The multiple-fracture solution is derived using a new uniform-flux solution for a single arbitrarily-oriented fracture in an anisotropic reservoir. The variables in this solution are: fracture half-length, fracture conductivity, and fracture angle of rotation for each fracture relative to the primary fracture. Example constant-rate type curves are provided for two intersecting fractures – cruciform or oblique – and three intersecting fractures – trifracture.
BHA and Drillstring Modeling Maximizes Drilling Performance In Lateral Wells of Barnett Shale Gas Field of N. Texas
Authors: Janwadkar S. S. , Fortenberry D. G. , Roberts G. K. , Kramer M. , Trichel D. K. , Rogers T. , Privott S. A. , Welch B. , Isbell M. R.
Published: December 2007

The Barnett Shale field of North Texas is one of the most prolific and fastest growing natural gas fields in North America with a multi-trillion cubic feet equivalent upside potential. However, the area presents numerous drilling challenges. In the vertical section, roller cone bits had unacceptable low penetration rates while PDC bits suffered premature damage. High torque and drag along with low penetration rates hampered drilling the curve and lateral sections. To address these challenges, a detailed engineering analysis was performed utilizing sophisticated BHA and drill string modeling software. Engineers studied offset wells and drillstring modeling including buckling load analysis, critical speed analysis, and torque and drag analysis.

As a result of the study, engineers determined that bit whirl and stick-slip were resulting in premature bit damage and reduced ROP while drillstring buckling resulted in inefficient transfer of weight on bit. Modeling helped design a BHA that mitigated buckling while optimized drilling parameters avoided critical speeds. The improvements resulted in 42% to 121% higher penetration rates with minimal damage to the PDC bits. The 83/4" vertical section was drilled in one PDC run in 60 out of 104 wells resulting in significant reduction in rotating hours and average cost per foot. The new BHA reduced drillstring buckling and significantly reduced torque and drag while drilling the curve and lateral sections.

The authors will describe the significance of applying principles of buckling load and torque and drag analysis; to design technically sound BHA's. They will also discuss how to utilize drillstring dynamics to avoid critical speeds.
Dynamic Modeling of Partial Liquid Lift for Stripper Gas Wells
Authors: Rastegar Moghadam R. , Khoshnevis B. , Ershaghi I.
Published: December 2007

This paper presents the results of a dynamic modeling approach for prediction of the critical rate to unload stripper gas wells. Methodologies in the literature such as the ones by Turner et al1and Coleman et al2 predict critical gas rates by using force balances based on bulk properties of the liquid and gas column. Using a one-dimensional modeling of two phase flow in a vertical column, we are able to incorporate the phase behavioral effects caused by temperature and pressure changes affecting fluid density and localized conditions of liquid droplets demonstrating a more accurate way to predict critical gas rates.

The dynamic prediction model allows incorporation of the formation depth and pressure, temperature gradients and tubing size. Gas composition ranges from dry gas to rich gas with potential for condensate formation. The model allows mapping and tracking the phase behavior conditions after flow stoppage under the condition of low gas rate and predicts the energy requirement to partially lighten the liquid column and resuming gas flow.
Reducing Electric Pumping Consumption in Mature Fields: Case Studies
Authors: Reedy M. A. , Ershaghi I.
Published: December 2007

There are about 640,000 pumping units nationwide consuming over 50,383 gigawatt-hours (GWh) annually. Based on a study conducted for the California Energy Commission1, more than 45% of these pumping units in California may be operating so inefficiently that their electric power consumption is often 8-10 times more than an efficient pumping system. Other studies and papers have suggested that energy saving projects are viable and economically attractive. However, operators are not actively pursuing these types of projects. The PTTC "PUMP" sponsored by the U S Department of Energy identified several reasons why operators hesitate to take advantage of technologies to improve efficiency and reduce operation cost. For many operators implementing corrective measures involves uncertainty, a misunderstanding or a lack of trust about new technologies. Operators resist change when they do not understand its implications and perceive that it might cost them much more than they gain. Wells operated inefficiently may prematurely experience their economic limit further affecting our domestic production. Continued long-term pumping inefficiencies have negative implications for the operator, for the fields and for the nation's power grid. This paper includes specific information on actual energy reduction projects installed by small producers in California including production impacts, project costs, energy savings, and project economics.
Scale-Inhibitor Testing for Multiphase Pipelines in a Subsea-to-Shore Development With a Closed MEG-Loop System
Authors: Halvorsen E. N. , Halvorsen A. M. K. , Ramstad K. , Tydal T. , Biørnstad C.
Published: December 2007

The sub sea development of the Ormen Lange gas field located in the Norwegian Sea will use MEG (mono-ethyleneglycol) for hydrate inhibition. Gas, condensate and MEG + water will be transported through a multiphase carbon steel pipeline to the onshore process plant at Nyhamna located on the west coast of Norway.

pH adjustment and film forming corrosion inhibitor will be used to control the corrosion rate in the pipeline. Although the corrosion rate is low during production, iron will be produced due to corrosion and follow the MEG/water phase. Most of the iron will be removed as iron carbonate particles during the MEG regeneration process but about 10ppm iron as particles and ions is expected to circulate in the MEG-loop.

Production of formation water will result in carbonate scaling when pH stabilised MEG is used as corrosion control unless a scale inhibitor is used. Three commercial scale inhibitors have been tested for this system. Tests have been performed without iron, with iron ions and with iron carbonate particles present. The results from the tests showed that the scale inhibitor concentration had to be increased considerably when iron ions were present compared to experiments without iron. The scale inhibitors performed poorer at the same inhibitor concentration in tests where iron carbonate particles were present than in tests with iron ions. Scale inhibitor concentrations up to 400ppm were used in the tests without achieving satisfactory scale protection when iron particles were present.

In addition tests with lowering the amount of pH stabiliser have been performed. Tests with combining scale and corrosion inhibitors have also been performed. No scale inhibitors have shown satisfactory performance when iron carbonate particles were present in the tests.