bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydraulic Fracture Optimization with a p-3D Model
Authors: Pitakbunkate T. , Yang M. , Valkó P. P. , Economides M. J.
Published: September 2011

In 2002 we introduced the concept of Unified Fracture Design (UFD) as a coherent way to size the fracture geometry for the expressed purpose to physically optimize the well performance. We used the Proppant Number as a correlating parameter, which in turn provided the maximum dimensionless productivity index (JD) which corresponds to the optimum dimensionless fracture conductivity, CfD. Once the latter is determined, the fracture dimensions, i.e., fracture length and width, are set.

If one assumes the fracture height is known and constant then the calculation is simple and a 2D fracture propagation model can be used. However, fracture height is not constant throughout the fracture and it cannot be considered constant during execution, depending greatly on the net pressure and vice versa.

We are presenting here an iterative procedure where the fracture height is related to the net pressure. In the procedure, for any assumed net pressure, the fracture height, along with the mass of proppant and the permeabilities of the reservoir and the proppant, lead to the Proppant Number which in turn determines the desired length and width. A fracture propagation model, such as the PKN geometry for lateral growth, coupled with a changing fracture height, leads to the calculation of the net pressure which is compared with the one assumed. Convergence of the assumed and calculated net pressure is what is sought.

The design procedure presented here is for both oil and gas wells. The design also includes the calculation of required treating pressure and finally it incorporates economics for production enhancement optimization beyond the physical optimization using UFD. Comparison of the 2D to the p-3D results points to the need and importance of the p-3D in a large array of reservoirs.
Factors Governing Distance of Nanoparticle Propagation in Porous Media
Authors: Caldelas Federico , Murphy Michael J. , Huh Chun , Bryant Steven L.
Published: September 2011

With a number of advantages hitherto unrecognized, nanoparticle-stabilized emulsions and foams have recently been proposed for enhanced oil recovery (EOR) applications. Long-distance transport of nanoparticles is a prerequisite for any such applications. The transport of the particles is limited by the degree to which the particles are retained by the porous medium. In this work, experiments that quantify the retention and provide insight into the mechanisms for nanoparticle retention in porous media are described. Sedimentary rock samples (Boise sandstone and Texas Cream limestone) were crushed into single grains and sieved into narrow grain size fractions. In some cases, clay (kaolinite or illite) was added to the Boise sandstone samples. These grain samples were packed into long (1 ft–9 ft) slim tubes (ID = 0.93 cm) to create unconsolidated sandpack columns.

The columns were injected with aqueous dispersions of silica-core nanoparticles (with and without surface coating) and flushed with brine. The nanoparticle effluent concentration history was measured and the nanoparticle recovery was calculated as a percentage of the injected nanoparticle dispersion. Fifty experiments were performed in this fashion, varying different experimental parameters while maintaining others constant to allow direct comparisons between experiments. The parameters analyzed in this work are: specific surface area of the porous medium, lithology, brine salinity, interstitial velocity, residence time, column length, and temperature.

Our results indicate that retention is not severe, with an 8% average of the injected amount, for all our experiments. Of the parameters analyzed, specific surface area was the most influential, with a linear effect on nanoparticle retention independently of lithology. Larger salinity increased nanoparticle retention slightly and delayed nanoparticle arrival. Velocity, residence time and sandpack length are coupled parameters and were studied jointly; they had a minor effect on retention. Temperature had a marginal effect, with two percentage points greater retention at 80°C compared to 21°C. Both surface coated and bare silica nanoparticles were successfully transported, so surface coating is not a prerequisite for transport for the particle and rock systems studied.
Integrated Workover and Re-completion Techniques to Successfully Restore Productivity for Sour Gas Field, Turkmenistan
Authors: Zou Honglan , Wang Xugang , Kang JianLi , Deng Minmin , Wang Qinghua , Zhu Huaishun , Gao Chengwu
Published: September 2011

This paper describes integrated workover and re-completion techniques to successfully restore productivity of Saman gas reservoir, a carbonate reservoir with H2S (vol. 3.0%) and CO2 (vol.3.6%) in Turkmenistan. Using existing old wells that have ever been producing for 5 years and already shut-in for more than 13 years is an excellent and economical way to increase production with a small investment.

Lots of complex situations in the wellbore and safety challenges, such as unmanageable wellbore corrosion, casing leak, string fishing, re-completion etc., could be encountered for existing sour wells. As a special corrosion diagnostic technology, MIT/MTT logging was used to acquire the data of metal loss, casing damage profile and cross section for joint. Workover strategies were considered and the best one was selected for complexities of old gas producers. Bottom whole assemblies (BHAs), mainly composed by SSSV system, chemical injection value and permanent packer, and were designed to corrosion control and long-term production safety. Nodal analysis and hydrate prediction were applied to optimize gas production system. Matrix acidizing by using viscoelastic self-diverting acids was carried out to remove damage for existing old wells. These key workover were conducted successfully for 17 existing well, resulting in average gas production of 30.6MMSCF from original gas production of 14.1MMSCF, and a gas productivity of 1,589 billion SCF/y. Compared with drilling new well, Workover not only economize on cost, but also speed up the building of gas field capacity.
Does Rock Really Weaken During Acid Fracturing Operations?
Authors: Joel E. O. , Pournik M.
Published: September 2011

Acid fracturing is a stimulation process in which the dissolution of the fracture faces creates conductivity after fracture closure. The resulting fracture conductivity depends highly on the amount and pattern of etching in addition to the strength of asperities. While there has been significant amount of studies on enhancing fluid systems to generate more optimum etching pattern, etched width, and etched length, there has been minimal work on understanding how the acid systems influence rock strength and affect closure of fracture under stress.

A systematic review of all available data on rock strength used in acid fracture modeling was conducted with emphasis on determining errors involved in each measurement. Furthermore, a detailed review of documented effect of acid on rock strength was also undertaken to understand how acid changes fracture face strength. Finally, the impact of errors in rock strength values used in conductivity correlations was studied in order to determine the importance of using correct values for rock strength.

Based on analysis of measured rock strength measurements, an average of 20% has been observed in data with greater errors for dolomite formations. Furthermore, there are great variations among rock strength values among different studies, with variations up to six times. In terms of effect of acid on rock strength, the measured weakening of rock of an average of 15% is within the measurement error limits and hence no conclusion can be made on acid weakening rock strength. Effect of errors in rock strength values used in conductivity correlations suggests significant errors in conductivity estimation, especially for softer rocks and higher closure stresses.

There have been many developments in enhancing the performance of acid fractured wells. However one major reason for the lack of success is limited understanding of the effect of acid on rock strength and incorrect estimation of rock strength. In order to understand the effect of acid fracturing on rock strength and resulting fracture conductivity under closure stress, a better method of measuring rock strength is needed in addition to detailed study on the effect of treatment parameters including acid type and contact time on rock strength variation.
Simulation Based Well Performance Modeling in Haynesville Shale Reservoir
Authors: Wang Jianwei , Liu Yang
Published: September 2011

Horizontal well completion and stimulation technologies are the keys to successfully develop shale gas reservoirs. The impacts of hydraulic fracture parameters, hydraulic fracture induced complex natural fracture system, and rock characteristics to well performance need to be clearly understood. Numerical simulation based methods provided a better way over other conventional methods for modeling well performance in shale gas reservoirs. However, current numerical simulation methods, dual porosity modeling and discrete modeling, have following limitations: 1) time-consuming in setting up hydraulic and natural fracture systems; 2) large computation time required.

We developed a new methodology to simplify hydraulic and natural fracture systems. Since large variations in natural fracture distribution and reservoir characteristics may result in unpredictable complex fracture network that cannot be accurately represented by discrete modeling, the hydraulic fracture and hydraulic fracture induced complex natural fracture system are treated as one enhanced zone. The simplified coarse dual porosity simulation model enables us to evaluate the effectiveness of stimulation treatment and understand shale gas production mechanism in a short time. To validate the new methodology, simulation results of a fine-grid reference model were compared with the simplified model. The simplified model greatly decreases simulation time and provides accurate results.

We applied this methodology to Haynesville shale gas wells. Historical gas production and flowing BHPs were matched. Reservoir and enhanced zone parameters were obtained after history matching, including porosity and permeability of the matrix and natural fracture system, half length, width, and permeability of the enhanced zone, as well as EUR. Simulation results indicate that if conductivities of enhanced zones are in same order shorter enhanced zone is corresponding to sharp production decline, while long enhanced zone is corresponding to relatively slower production decline. Conductivity of enhanced zone is the controlling factor for early time production performance and behaviors of flowing BHPs, while Matrix permeability and SRV half-length are the controlling factors for late timeproduction performance. Sensitivity analyses then were conducted to quantify the impact of the reservoir characteristics and enhancedzone parameters. The simulation results provided insights into effective stimulation designs and flow mechanism for shale gas reservoirs.
Case Study of Unconventional Gas Well Fracturing in Hungary
Authors: Shaoul Josef R. , Spitzer Winston , Delft StrataGen , Dahan Matthew W.
Published: September 2011

Well Ba-E-1 was drilled in the Tompa prospect (now the Ba-IX Mining Plot) in Hungary targeting the Miocene and Cretaceous formations between 2600 and 3500 mTVD. These are tight sandstones and the expected permeabilities were in the range of 0.001 to 0.5 mD. Two hydraulic fracture treatments were performed. The first fracture treatment was in the lower part and the second treatment was in the upper part of the deepest interval. With no previous propped fracturing experience in this field, the first treatment was designed as a conventional crosslinked gel treatment to minimize the risk of a premature screenout. Following the analysis of the data from the first zone, it became clear that the average permeability was closer to the minimum expectation of 0.001 mD. Due to lower than expected stimulation effectiveness of the first fracture, and the confirmation of the low permeability, the 2nd fracture treatment was changed to a waterfrac design. This formation clearly falls into the category ‘unconventional’, and consequently was a good candidate for a waterfrac.

This paper describes the pre-frac diagnostics, fracture execution and post-frac production evaluation of this unconventional gas well. Special emphasis is placed on the use of small volume injection tests (DFIT) to obtain an estimate of the in-situ kh, since it is impossible to perform pre-fracture welltests in such a formation. The result of the DFIT analysis is then used to constrain the post-fracture welltest analysis in a numerical simulation model that includes fracture filtrate cleanup modeling. Post-frac analysis showed that the initial proppant pack damage is high and effective fracture length is much smaller than the created length, especially with crosslinked gel. The crosslinked gel treatment was not able to cleanup effectively, and therefore showed limited stimulation effectiveness. The first ever waterfrac in a gas reservoir performed in Europe showed a more significant production improvement during the short post-frac test. The results from this well suggest that, as in North America, waterfracs appear to have better initial production than crosslinked gel fracs due to better fracture cleanup in European reservoirs with micro Darcy permeability.
The Acorn Discovery: An Innovative Appraisal of an Offshore, Low Deliverability, HPHT Reservoir
Authors: Wood P. , Verlinden V. W. , Coghlan G.
Published: September 2011

Significant hydrocarbon volumes are present in heterogeneous, low permeability, HPHT reservoirs in the Central Graben area of the North Sea. In order to properly appraise these accumulations, an innovative appraisal strategy is required, which has to dovetail with hazard management and cost containment. In order to lower development risks these may include elements such as an extended well test and permanently installed optical distributed temperature sensor (DTS) system to monitor the flow profile.

A case history is presented of a recent appraisal well drilled on the Acorn discovery, UKCS block 29/8 in the Central North Sea. Significant STOIIP has been mapped in the continental sandstones of the Triassic-age, Skagerrak formation, where reservoir connectivity and resulting commercial productivity was the key uncertainty. A high-angle well was drilled to maximise reservoir exposure, and completed with a DTS system to monitor inflow from different layers. An extended well test was conducted and 50,000 bbls withdrawn. A data-logging device was left on the wellhead to record pressure build-up. The DTS system provided continuous flow profile information.

Well construction, completion and flow testing was successfully achieved on time and budget and was a credit to the meticulous planning and execution by the Centrica wells’ team. The required dataset was acquired for the subsurface team, much of it in real-time.

Ultimately a decision to not develop the accumulation was taken following evaluation of all data from the well. Data collected showed reservoir connectivity to be too low to support a development. Percolation theory suggests that a threshold value of N:G constrains the reservoir type encountered. The discovery appraised is interpreted to be below this threshold; however the information collected is pertinent for determining the viability of other such discoveries.
Integration of 4D Seismic Data for Water Injection Analysis of Co-mingled Wells
Authors: Ali A. , Brechet E. , Prat P. , Vert M.
Published: September 2011

4D seismic has been utilised on several fields for improved reservoir monitoring and management. This paper describes a specific application of 4D seismic data for the analysis of co-mingled injectors.

For optimised pressure support and sweep in water-flood projects, an injector can be completed over several different reservoir units. This, however, can introduce uncertainty on the effective injection into each zone. The reservoir quality encountered at each zone can give an indication of expected injectivity, however, this does not take into account dynamic pressure effects in the reservoir and possible completion issues. In certain cases where injection intervals are changed over time, monitoring the changes in the injectivity index during these different modes of operation can be used to infer relative injectivity potentials. PLT results, when available, can also indicate the split of injection into various zones at a given point in time. In addition, if formation pressure data is acquired after production start-up, this can be used to assess the pressure regimes in different zones. 4D seismic monitoring is the only technique to give an areal view of the reservoir, and injection anomalies from 4D seismic interpretation (3D geobody envelopes) can be used to represent the cumulative injection into a particular zone at the time of the monitor survey.

This paper contains illustrations for the comparison of injection split estimates from reservoir quality (logs), well injectivity analysis, production logging, formation pressure testing and 4D seismic monitoring. Consistency between these various data sources reduces uncertainty for important reservoir management and field development decisions (well interventions, infill planning etc.).

4D seismic has proved to be beneficial for the field development and reservoir management of many Angola Block 17 fields and this particular example demonstrates the efficacy of integration of several data sources for effective injection analysis on one such water-flood field.
Experimental Investigations of DDP and SCWD in a Naturally Fractured Reservoir, HP/HT
Authors: Gachuz-Muro Heron , Miguel-Hernandez Nemesio , Rodriguez-Roman Jesus , Luna-Rojero Erick , Aguilar-Lopez Berenice
Published: September 2011

The use of the Double Displacement Process (DDP) has received considerable interest as a method of Enhanced Oil Recovery (EOR). The DDP has already studied in several fields and yielded promising results. This process consists of injecting gas into waterflooded oil zones. The Second Contact Water Displacement (SCWD) Process is an extension of the DDP and consists of injecting water after a DDP. In general, fractured reservoirs have always been considered poor candidates for enhanced oil recovery; this is mainly due to the complexities involved in predicting performance in such reservoirs.

This paper investigates the efficiency of oil recovery using DDP and SCWD in a group of fractured cores. It was necessary to stack several core plugs in order to obtain accurate volumetric results. Two experiments were designed to illustrate both natural depletion and tertiary gas injection under extreme conditions; it means 5520 psi and 280.4 °F (HP/HT). Natural and nitrogen gas were used during the experiments. Results indicate that injection of natural gas in naturally fractured reservoirs with light oils could significantly recover more oil, compared to N2 injection (DDP). The study reveals that a significant amount of residual oil will be recovered by tertiary gas injection in a mature oil field where the water injection has been used during a long period. Finally, a second water displacement (SCWD) was carried out to evaluate additional recovery factors.
Real-Time Drilling Parameter Optimization System Increases ROP by Predicting/Managing Bit Wear
Authors: Gidh Yashodhan , Ibrahim Hani , Purwanto Arifin , Bits Smith
Published: September 2011

Tool manufacturers have made significant progress improving downhole drilling technologies, but little effort has focused on optimizing the drilling process. The set-it-and-forget-it approach and inherent inefficiencies of the automatic driller are inadequate for keeping bit parameters matched to lithology and wellbore conditions. The industry requires a new methodology to help rig-site personnel make informed drilling parameter decisions based on real-time offset data analysis that increases operating efficiency to reduce drilling costs.

To solve the problem, the service provider launched an artificial neural network (ANN) drilling parameter optimization system (DBOS OnTime) which provides rig-site personnel real-time information to ensure maximum run length from all bits and downhole tools at the highest possible penetration rates (ROP). Benefits of the new system include extended tool life, fewer trips and the ability to manage the bit's dull condition.

The objective is to replace the human factor of applying operating parameters such as weight on bit (WOB) and RPM with the intelligent ANN "learned experience." By using the ANN based software system, operating parameters can be selected based on the documented physical rock characteristics (offset log data) of the formations being penetrated and then fine tuned for the bit's specific cutting structure and wear rate. By following the real-time ANN recommendations, changes can be implemented to increase overall penetration rates (ROP) while maximizing bit life by managing the dull condition.
Probabilistic Reservoir Simulation Workflow for Unconventional Resource Play: Bakken Case Study
Authors: Luo Shanqiang , Wolff Martin , Ciosek Jessica , Rasdi Faisal , Neal Lane , Arulampalam Pathman , Willis Sean
Published: September 2011

It is widely accepted that unconventional resources hold enormous reserve potential. However, complex fluid flow physics and completion/stimulation practices pose a unique challenge in estimating reserves or making long-term production forecast for these unconventional reservoirs, as traditional methods are most often not applicable. This paper proposes the application of a probabilistic reservoir simulation workflow to provide realistic range of production forecasts with successful application in the Bakken unconventional tight oil reservoir. First, geomodels are constructed and ranked. Then, key static and dynamic uncertainty parameters are identified for the subsequent history-matching study (with each of the geomodel realizations) that provides not only production forecast for individual wells but also parameter ranges for experimental design (DoE) for field-level prediction. Then, DoE simulations are conducted to construct proxy equations that are used in Monte-Carlo simulations to generate Low-BTE-High response S-curves for the field-level models. Finally, based on these S-curve results, Low-BTE-High deterministic reservoir simulation models are constructed to generate corresponding long-term production forecast profiles for full-field development and optimization.
Fill-Up Test Process for Unconventional Gas Reservoirs (Case Study)
Authors: Megyery M.
Published: September 2011

Results of hydrocarbon exploration in Hungary indicated that most of the oil and gas accumulations were formed by a vertical migration from the sources of the deeper part of subbasins, which was due to the tectonic activity in contrast with tectonically stable provinces. 950 conventional oil and/or gas reservoirs were explored in this territory. I was a participant of these reservoirs’ well-tests and in the researches of the local unconventional reservoirs (coal bed methane; tight gas; high level radioactive waste geological disposal).

Fill-Up pressure test process, which is a method used for wells with low initial oil and gas production and deep drawdown, was patented. Besides such production conditions, the pressure buildup (PBU) data that were obtained by wellhead shut-in were inadequate for calculating formation parameters. After stopping the production, the Fill-Up process ensured the wells’ complete fluid saturation, thus, further possibility of flowing-in fluid was precluded and pressure buildup data equivalent to bottom hole shut-in were provided. The advantage of the Fill-Up method is that it can be completed at any well constructions; furthermore the fluid transmits the bottom pressure-changes to the surface (this is a kind of surface readout).

During our practice, 121 gas-wells were measured by Fill-Up, 75 of them gave reservoir parameters. After Filling-Up at these wells the pressure started to increase. After Fill-Up, pressure decline was found in 35 wells. Based on our experience, the production of these parts of the reservoirs could not be increased.

The use of the Fill-Up method at unconventional reservoirs will give us reservoir parameters or other information which will improve the planning and implementation of the formation treatment. This way a part of treatments can be omitted.
Downdip versus Updip Gas Injection Evaluation in a Deepwater Development
Authors: Sadikoglu Kasim , McQueen Matt , Sweatman Mark
Published: September 2011

Downdip versus updip gas injection options have been evaluated for a deepwater multi-reservoir development discovered and appraised over the last few years. At the time of the study, the development plan called for gas injection in the Alpha field until gas export to the mainland became available. The name of the field has been changed to preserve confidential data.

The depositional model of the Alpha field envisages stacked turbiditic channel systems meandering from east to west. The field is tilted approximately 30 degrees north-south due to post-deposition tectonic movement. As a result, the apex region of each meandering channel may form attic-traps that can only be swept by a fluid lighter than oil. Whilst downdip gas injection offers the potential of recovering the oil in these attics, it also carries the risk of gas over-running towards updip producers causing excessive gas production.

A study was performed to assess various gas injection scenarios using 2D and 3D reservoir simulation. A simple model utilising a single channel at various dip angles was built prior to any detailed simulation to study fluid movements and demonstrate proof of concept. Fully integrated geological sector and full-field models were then constructed using an object-based modelling technique to assess downdip and updip gas injection options in multiple equiprobable stochastic realisations.

The study concluded that counter to conventional thinking, downdip gas injection both delays gas breakthrough and recovers more oil in this reservoir. These benefits were the result of: Downdip injection scenarios offering greater opportunities for gas solution in the highly undersaturated oil prior to accumulation at the crest;Increased offset between producer and injector.Displacement of trapped oil in tilted-channel attics improving sweep;

Based on the outcome of this study, downdip gas injection was integrated into the development plan. Later developments in the project enabled gas export from first oil, rendering gas injection unnecessary.
An Experimental Investigation of Carbonate Rock Wettability after Stimulation Fluids Invasion
Authors: Saneifar M. , Fahes M. , El Cheikh Ali N. , Zoghbi B. , Hill D.
Published: September 2011

Trapping of spent acid after acidizing job is a major problem in carbonate rocks. Spent acid needs to be fully mobilized and recovered in order to enhance gas production. Wettability of the rocks and capillary forces are the main reason behind fluid trapping in carbonate formations. These forces can be weakened by decreasing surface tension and increasing contact angle. Additives that are injected along with the acid can have an impact on changing the surface tension, contact angle and possibly the wettability of the rocks. Previously, separate studies were conducted on the effect of acid additives on contact angle and surface tension. However, there is still a need to investigate the overall impact of acid additives on these two parameters and wettability on the trapping of spent acid in the carbonate rocks.

In this paper, the full impact of two additives, formic acid and methanol, on trapping and wettability is investigated. Irreducible fluid saturation is compared before and after the exposure of rocks to spent acid. Formic acid decreased irreducible fluid saturation whereas methanol increased irreducible fluid saturation. Spontaneous water imbibition was conducted in each case to ensure that there is no permanent effect on rock wettability as a result of using these additives. It is very important to understand that the effect of various additives on wettability must be studied before any acid job, as their impact on wettability can consequently affect well productivity.
Improved Understanding of CO2/Foam EOR Techniques by Aid of Tracer Technology
Authors: Dugstad Øyvind , Opel Karsten , Fjelde Ingebret
Published: September 2011

Poor macroscopic sweep efficiency can be a problem in CO2-flooding of oil reservoirs. The macroscopic sweep efficiency can be low due to the combination of high mobility ratio, gravity segregation and heterogeneity. By decreasing the mobility of CO2 the macroscopic sweep efficiency can be improved. In the present work the surfactant, alpha olefin sulphonate (AOS), has been used as CO2 foaming agent. Dynamic flooding experiments have been carried out at realistic reservoir conditions to study the relative transport of water, CO2 and surfactant when foam is generated in the porous network. The surfactant has been labeled with the radioactive sulfur isotope 35S. The water has been labeled with the radioactive hydrogen isotope tritium (3H) and the CO2 has been labeled with the 14C isotope.

It is shown that the flow of the individual phases in a CO2-foam flooding can be monitored by using of tracer technology. Variations in the flow rates of surfactant solution and CO2 can be clearly detected, and the accessible pore volume can also be determined. AOS products contain different chemical structures. In the study, the main AOS components have been chemically separated prior to injection on the porous column. The transport of the individual components was shown to be different. In the reservoir, chromatographic separation of the AOS components may change the efficiency of the foam process.

The study has shown that use of tracer technology can be a powerful tool in study of transport mechanisms in CO2-foam flooding.
Gas Tracer Transport - Correct Formulation and Fast Post-Processing Simulation Technique.
Authors: Huseby Olaf , Sagen Jan , Dugstad Øyvind
Published: September 2011

This paper describes a fast post-processing method for simulating gas tracer transport. The partitioning between phases is described by a convenient and correct formulation. Gas tracers (e.g. per-fluorinated or radio-labelled hydrocarbons) can be used to trace injection gas during secondary recovery, CO2-injection for CCS or EOR etc. Laboratory experiments show that commonly applied reservoir simulation methods for gas tracer transport should be improved. This paper highlights the effect of gas tracer partitioning between phases and presents a formulation that can be used in practical reservoir simulations. A fast post-processing tracer simulation technique is introduced to solve the gas tracer transport in real-field reservoir cases. The formulation of the solution exploits the fundamental assumption that tracers do not affect the phase transport. The partitioning of the tracer components is solved fully coupled with the tracer transport. The post-processing is based on previously solved reservoir simulation runs and gives significant savings in CPU-time. Using laboratory results for several gas tracers, we observe that models based on commonly applied tracer formulations, are unable to correctly handle the tracer partitioning between the gaseous and oleic phases, and that the formulation presented here resolves that problem. Using real-field reservoir simulation cases, we demonstrate the practical improvement achieved. Our main conclusion is that a correct description of gas tracer phase partitioning is important to enhance predictions from gas tracer tests. The paper contributes to improved and rapid gas tracer simulation, important for correct interpretation of gas tracer results from inter-well tracer tests in petroleum reservoirs. The formulation of the equation and the simulation techniques described is also valid for other applications, such as water tracers, CO2-sequestration, non-aqueous phase liquids etc.
Sweep Efficiency in CO2 Foam Simulations With Oil
Authors: Liu M. K. , Andrianov A. I. , Rossen W. R.
Published: September 2011

We simulate gravity segregation and sweep in foam EOR in miscible and immiscible displacements of oil to investigate the effect of oil on foam sweep and the usefulness of simple models designed to predict the extent of gravity override with foam. Comparison of simulation with analytical models highlights limitations of both approaches. In 1D simulations with fine grids, both first-contact and multicontact miscible displacements fit the fractional-flow model for miscible foam floods (Ashoori et al., 2010). In simulations of either sort of displacement, the "critical oil saturation" for foam stability is irrelevant because "gas" and "oil" never co-exist at the same location. Hydrocarbon kills foam abruptly at the point where the simulator changes the name of the nonaqueous phase from "gas" to "oil."

In 2D homogeneous reservoirs, the model of gravity segregation of Stone (1982) and Jenkins (1984) must adapt to an inhomogeneous mixed zone for two reasons. First, if pressure varies greatly in the mixed zone, then foam mobility varies there, because in many foam models foam mobility is a function of gas viscosity. In reality, foam mobility is not sensitive to viscosity within bubbles. Second, residual oil saturation can vary in the mixed zone. For miscible displacements Stone and Jenkins' equations work well if one takes gas properties at the middle of the mixed zone. For immiscible displacements, the variation of residual oil saturation in the mixed zone can make the distance to segregation of gas shorter or longer than predicted by Stone and Jenkins depending on whether residual oil kills foam or not.

"Modified SWAG" injection (injecting water simultaneously above gas) gave from 70 to 130% greater sweep than co-injection at the same injection rates in our simulations.
Ni-Fe Nanoparticles: An Innovative Approach for Recovery of Hydrates
Authors: Bhatia Kutbuddin , Chacko Levin
Published: September 2011

Gas hydrate is a crystalline solid consisting of gas molecules, each surrounded by a cage of water molecules. They produce 160 times their volume of methane which is an infinite source of energy waiting to be tapped, but the technology to recover these hydrates is at its infancy. Recovery of gas from hydrates requires the dissociation of gas hydrates which can be accomplished in at least three ways: thermal recovery, depressurization or by chemical inhibition. But, the problems associated are: Most chemical additives (salt, methanol, and glycol) cause pipe and equipment corrosion, ecological problems.Preheated gas or liquid transportation down to hydrate zone is accompanied by extensive heat loss.Microwave or electromagnetic method also requires vast energy transfer to decomposition zone and is inefficient.

This paper proposes the injection of air-suspended self heating Ni-Fe nanoparticles (50 nm) in the hydrate formation through horizontal well. These particles will penetrate deep into the class I, II and H hydrate reservoir by passing through the cavities (86–95 nm).

The self heating of particles in a magnetic field is caused by hysteresis loss and relaxation losses. These particles cause temperature rise up to 42 °C in formation leading to disturbance in thermodynamic equilibrium and causing the water cage to decompose and release methane. In this technique, the pressure of the fluids in contact with hydrate is lowered, pushing the hydrate out of its stability region and leading to its decomposition.

It has been discovered that the less expensive, readily available Eggwhite (Ovalbumin) can catalyze the reaction which results in large scale formation of these nanoparticles. The main advantage of this technique is the very low dosage requirements (small quantity required for 1m3 of Hydrate decomposition). Moreover, the nanoparticles used are non-poisonous, environment friendly.
Integration Of Seismic Lithology Data In The Reservoir Model
Authors: Calabrese M. , Pirera F. , Rossi M. , Scaglioni P. , Tosoratti F.
Published: September 2011

The Marulk field is a gas condensate accumulation located in PL122 in the Norwegian Sea. The field was discovered in 1992: hydrocarbons were encountered in Lysing and Lange formations. The field is operated by EniNorge and it will be put on production with a direct tie-in to the existing Norne FPSO.

An update of the reservoir model was based on a new acquired high-quality Q-marine seismic volume, and reservoir properties were distributed using the geophysical attributes: a successful elastic seismic inversion was performed and used as input to the lithology classification study. This supervised Bayesian classification made use of multivariate Probability Density Functions (PDFs) of selected inverted attributes for each litho-class as a-priori information to constrain the classification. Litho-class selection started by analyzing raw and interpreted logs at well locations and petrofacies obtained by means of an integrated petrophysical model. Eventually a new class subdivision was obtained, closely reflecting not only the well data but also the actual geophysical response.

This approach resulted in a quantitative estimate of the uncertainty in lithology prediction: significant maps were extracted from Probability volumes of geophysically consistent lithology classes. The obtained probability maps allowed driving the facies distribution in the 3D grid improving the reservoir architecture knowledge and providing a valuable link among seismic data, logs, petrofacies and sedimentological model.
Ultrasonic Peening, a Solution for Fatigue Cracking on Offshore Installations
Authors: Hedmar M.. , Martinez L..
Published: September 2011

By using Ultrasonic Peening the service-life of an offshore installation can be extended.

Every floating installation will have weak spots in its structure, this is almost enivatble. We call these weak areas "fatigue hot-spots". In practice the fatigue hot-spots are the locations were the first cracks start to initiate in the structure; in affect these cracks will threaten the structural integrity of the structure. Ultrasonic peening is a pro-active solution to prevent fatigue cracks to initiate at these locations. The method is a practical and efficient solution for structural integrity challenges related to fatigue cracking. It can extend the service life of high stressed weld joints in an offshore platform by four times1 if the weld quality is adequate. Even though Ultrasonic Peening is a very efficient way to strengthen the integrity of offshore installation, the method will always be dependant on the existing weld-quality. As ultrasonic peening is a post weld treatment it can not magically transform a bad weld into a good weld, it can only enhance a good weld to an even better weld. Ocassionally Ultrasonic Peening Technicians comes across fatigue hot-spots with bad weld quality. In order to be able to estimate the benefit of Ultrasonic Peening even if the weld quality is inadequate, a couple of fatigue trails were designed to investigate this further.

Two seperate batches of F Specimens were manufactured.

-As- welded; used for reference purpose

-As welded + UP treated; Specimens were first put under fatigue cycles until ½ of the predicted fatigue life had been consumed, the specimens were then treated with the LETS Global Ultrasonic Peening Procedure, after these two steps the specimens were put back on the fatigue trail until failure.

It was made sure that all the specimens had a relatively bad weld quality. For example the weld toe angle was too high and the weld toe was filled with irragularities.

The results show that Ultrasonic peening doubles the fatigue life of a welded attachment eventhough; the weld quality is poor and even if the welded attachments have already consumed half of its fatigue life. This corresponds with American Bureau of Shipping’s official guidelines2.

This document focuses on the benefit of Ultrasonic peening on offshore installations which have already consumed a big part of their service life and have locations with bad weld quality. Since operators tend to focus on life extension of offshore installations beyond the original desgined service life at a relatively late stage, ultrasonic peening is often used when the welded attachments have used half or more of their intended service life.
Extended Draft Semisubmersible
Authors: Sablok Anil , Edelson David , Kim Jang , Luo Mike
Published: September 2011

An Extendable Draft Semi-submersible (EDS) is a low-motion floating production system concept focused on flexibility and low cost. An Extendable Draft Semi-Submersible (EDS) can support full drilling and production facilities that can be prepared for deployment at a dockside facility with limited water depth. The EDS combines the favorable features of deep-draft Semi-submersibles, Truss Spars and other reduced-heave floaters, making its in-place motions superior to shallower-draft floaters for supporting dry-tree risers and SCRs.

EDS is a self-installing design, which delivers and deploys a fully operational system without the aid of crane vessels. The EDS structure consists of a floatable deck, stabilizing columns and heave plate/pontoon connected to the bottom of the columns. The barge-type deck is designed to float the entire structure, including topsides, to the near shore site. Upon arrival, the columns and heave plate/pontoon is lowered down using strand jacks either in a single or dual direction mode and locked into the deck to the locking draft. The use of strand jacks allows the lowering operation to be performed in a higher sea state than normally used for offshore installation thereby increasing the operability. The deck is then raised to the operating elevation by de-ballasting the columns after pawls are engaged between deck and columns for rigid connection between them. The pawl connection between columns and the deck is reversible and the columns can be raised above the deck to enable the platform to be towed to a new location for redeployment or brought to quayside.

An alternative to the self-installing design is installing the topsides by a floatover technique, similar to what has been done for several semi-submersibles in Brazil.

The EDS motions are suitable for Dry Tree application and SCRs in different areas around the world including areas with severe storm environment like Gulf of Mexico, Weastern Australia, etc. The concept provides flexibility in constructing the EDS that facilitates a high level of local content in most areas of the world.

This paper describes the features of the EDS platform along with the fabrication and deployment offshore.
Evaluation of Navigation Quality of Non-Survey Logging or MWD Tools and Methods of Navigation Sensor Correction and Reconstruction
Authors: Tracadas Philip , Bonavides Clovis , Quirein John , Perkins Tegwyn
Published: September 2011

The techniques used to process open- and cased-hole image logging and other oriented tools that are run in offshore exploration and development wells require highly accurate navigation logs. Navigation packages usually consist of triaxial accelerometers and magnetometers that require calibration of the offset (bias), gain, and tool axis alignment for each sensor. Despite pre- or post-acquisition surface calibrations, the downhole environment will alter calibrations of offset and gain as a result of many factors, such as temperature and electrical noise. These factors are impractical to characterize or predict, and it is impossible to completely isolate the navigation package from these factors. Experience shows that the offsets and gains of the sensors may change appreciably over time scales much shorter than the total logging time.

This paper provides four detailed examples of possible navigation logs with various problems to develop a methodology for evaluating their quality and proposing corrective action. The goals of this study are to determine which navigation sensors to adjust or which sensors are not responding to the appropriate Earth field and need reconstruction. The paper proposes several quality measures for identifying, from the navigation log, drift in sensor response, including measured total field variations and correlations of tool deviation to tool rotation.

When the methods described in this paper are used to align images with respect to a geographical reference (in cases where the navigation was affected by sensor failure or external factors, e.g., permanently magnetized formation layers, that alter the sensor calibrations), they significantly enhance the navigation quality. For example, image logs that originally wobbled erratically in ferrous formations can be oriented to the north allowing dipping-bed orientation to be measured. In addition, magnetometer reconstruction and accelerometer correction can easily manage oriented navigation in metal casing. In general, the algorithms developed in this study assume that a rough surface calibration is available to obtain an initial solution, but time is no longer required for meticulous wellsite surface calibration.
Case Study: The Research Progress of Using Stimulation Technologies in Horizontal Wells to Develop Low-permeability Reservoirs
Authors: Jianwen Yan , Yurong Zhang , Wenjun Wang , Cheng Cai , Na Zhang , Bairu Shi
Published: September 2011

In the last three years, the horizontal well technology was developed at high speed in PetroChina, and the number of applications was more than 3000 by the end of 2008. This paper focuses on the stimulation technologies in horizontal wells and the latest research progress of using them to develop low-permeability reservoirs in PetroChina. To solve the problem in the development of low-permeability reservoirs, PetroChina carried out the researches including the adaptability study of drilling horizontal wells in low-permeability reservoirs, the matching relationship study of horizontal wells with different well patterns, the stimulation technologies, such as fundamental acid fracturing technology, staged hydraulic fracturing technology in a perforation completed horizontal well, liquid slug staged fracturing technology, mechanically staged fracturing technology and limited-entry fracturing technology, etc. Several breakthroughs had been made in the key technology research, and the new technology had been applied to 405 wells in field tests, which acquired good effect during 2007 to 2009. After stimulation, the maximum individual well production came up to 4.2 times of the adjacent wells, and a great deal of experience had been accumulated during these tests at the same time which would provide technical support for the application of horizontal wells in the development of low-permeability reservoirs.