bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Injection EOR Optimization Using Fiber-Optic Logging with DTS and DAS for Remedial Work
Authors: Fitzel Steve , Sekar BK , Alvarez Domingo , Gulewicz Dale
Published: October 2015

The evaluation of in-flow performance for all stages in pumping, multi-stage fractured horizontal (MSFHW) oil wells is challenging with conventional production logging tools. The successful deployment of fiber-optic sensing technology has been influential in diagnosing gas breakthrough in producing wells of a gas injection EOR project by providing real-time, full well in-flow profiling. The integrated operation of a multi-disciplined team and the outcomes will be described.

An operator commenced a tertiary dry gas injection enhanced oil recovery (EOR) in the Bakken Formation of southeast Saskatchewan, Canada. The pilot project was designed as a 1:8 toe-heel injection pattern, with a one mile horizontal in-fill well supporting eight perpendicular producers. The offset producers are monitored using regular production data and gas breakthrough has been found in certain fracture stages that are in communication with the injector. A program was developed to use real-time fiber-optic DTS and DAS to identify the stages with gas channeling in the producer for corrective action.

Distributed Temperature Sensing (DTS) utilizes the Joule-Thompson (J-T) cooling principle as the gas enters the frac port and expands into the liner, while Distributed Acoustic Sensing (DAS) captured the amplitude and frequency of acoustics from the fluid flow. Simultaneous measurements of DTS and DAS were taken using a hybrid fiber/electric wireline inside coiled tubing. The artificial pumping system was pulled out of the producer and coiled tubing was run to the bottom of the well. Real-time pressure and temperature sensors were run on the end-of the coil and a memory gauge at the bottom of the swab string. The well was stabilized overnight before swabbing and monitoring. A service rig was used to swab the well and establish a draw-down. Live down-hole DTS, DAS and pressure data were logged and monitored at the surface and remotely.

Post-processed data interpretation from three wells in the EOR project will be discussed that shows DTS and DAS logging is a valuable technique in detecting injected gas channeling. The results were effective in making decisions about shutting off the problem stages. DTS was most effective since gas has a higher J-T coefficient compared to oil and water. The DAS data supplemented and confirmed the DTS data. Having real time downhole pressure measurements allowed for regulating the swabbing rates to obtain the desired drawdown pressure.

Gas injection EOR projects can be optimized using fiber-optic sensing while swabbing. It provides a new and effective tool in identifying gas breakthrough for remedial work.
Modeling Production Decline in Liquid Rich Shale (LRS) Gas Condensate Reservoirs
Authors: Khanal A. , Khoshghadam M. , Makinde I. , Lee W. J.
Published: October 2015

Conventional DCA methods, developed for boundary dominated flow (BDF), yield unrealistic values for expected ultimate recovery (EUR) when used for unconventional reservoirs with long-duration transient linear flow. Moreover, the developed model parameters are not functions of reservoir properties and flow mechanisms. Although new models have been developed over the years to predict the linear flow, there is still no good way to forecast long-term performance of gas condensate reservoirs.

In this study, we use decline curve analysis, reservoir simulation and statistical analysis to understand the flow of hydrocarbons in LRS reservoirs and to estimate the ultimate recovery in LRS gas condensate reservoirs accurately. Initially, a synthetic reservoir model was constructed to replicate a limited case history available for the Eagle Ford Shale. Various sensitivities on reservoir parameters and operating conditions were performed to understand their effect on oil and gas EUR's after 30 years of production using design of experiments (DOE) and response surface modelling (RSM). Various decline curve methods were applied to the synthetic data obtained by using pressure normalized diagnostic plots. Results from this study shows that pressure normalization could potentially be used to identify the flow regimes in LRS reservoirs, which is especially true for rate restricted fields. We also observed that the production characteristics of LRS gas condensate reservoirs are highly variable, possibly due to the change in composition via liquid dropout. The approach of using two or more models with different production parameters by isolating the parameters provides a good fit to the data and a realistic estimate of the EUR. Statistical analysis of the reservoir parameters and the EUR shows that there is some relationship among them. Our study shows that these statistically developed co-relations are accurate for the reservoir studied and EUR for other wells in the same field can be obtained with variation of parameters.

We present a methodology which uses empirical decline curve analysis, physics based reservoir simulation and statistical analysis to forecast EUR based on limited production data in LRS gas condensate reservoirs. This study provides considerable insight into the long-term production behavior in LRS gas condensate reservoirs.
Sorption-Dependent Permeability of Shales
Authors: Lopez Bruno , Aguilera Roberto
Published: October 2015

Shale gas reservoirs are fine-grained, organic-rich rocks with a well-developed pore network structure within the organic matter (kerogen). Organic pores in shale reservoirs exhibit small radii in the range of 0.5 to 100 nanometers, which indicate that non-Darcy flow mechanisms are present in these rocks in addition to viscous flow. Gas adsorption/desorption and gas diffusion from solid kerogen are some other important flow mechanisms in shales. Therefore, consideration of these phenomena is crucial for quantification of permeability of shales. A numerical procedure to calculate permeability of shales that accounts for all the above factors is introduced in this work.

During shale's depletion, organic pore radius can change or remain approximately constant depending on the rates of adsorption and desorption. Previous investigations suggest that organic pore radius increases as desorption takes place, which in turn also increases the space available for free gas and reduces the amount of adsorbed gas. This phenomenon thus increases shale permeability. This paper goes further and indicates that pore diameter can increase, decrease or remain approximately constant with time depending on the on-going desorption, adsorption and diffusion from solid kerogen. The effects on pore radius and permeability of all these mechanisms, viscous flow and Knudsen diffusion are addressed in this paper with the development of a ID radial simulation model. Two independent methods, which approximately corroborate each other, are presented for calculating changes in pore radius.

Results show that considering pore radius changes due to sorption and diffusion have a significant impact on estimation of shale permeabilities. The effects on permeability vary under different reservoir conditions. The importance of solid kerogen as a gas source and its effect on gas flow is highlighted. The solid kerogen feeds organic pores affecting the rate of adsorption. Consequently the organic pore radius does not necessarily increase during production; it can decrease or even remain approximately constant. It is concluded that ignoring viscous flow, Knudsen diffusion and changes in pore radius lead to erroneous permeabilities. Gas diffusion from solid kerogen can be quite significant in shale reservoirs and should be taken into account.

The main contribution of this paper is the development of a numerical method for calculating sorption- dependent permeability of shales. The calculations include Darcy and diffusive flows, and changes in organic pore radius due to adsorption/desorption and diffusion from solid kerogen. This is the first time all the aforementioned mechanisms are analyzed in a single study.
Going from Conceptual to Analytical Drilling/Completions/Reservoir Guided Model of a Cased Uncemented Multi-Fractured Horizontal Well in the Canadian Horn River Basin
Authors: Virues Claudio , Lypkie Kevin , Pyecroft James , Zafar Hammad , Lehmann Jurgen , Hendrick Jason
Published: October 2015

This paper outlines a drilling, completions reservoir guided analytical model to assess cased uncemented (CUC) multi-fractured horizontal wells (MFHW) in the Canadian Horn River Basin. The typical Horn River shale gas development involves drilling and hydraulically fracturing multiple horizontal wells from a single surface pad location. The wells are hydraulically fractured in a sequential manner from the toe to the heel of the horizontal section, alternating from well to well. This manner of hydraulic fracturing allows concurrent operations that maximize operational efficiency and reduce completion costs. Microseismic (MS) data shows that hydraulic fracture stimulation results in a very complex stimulated reservoir volume (SRV). Surveillance data including MS as well as proppant and fluid tracer data shows that hydraulic fractures reactivate the natural fracture system and can extend beyond inter-well distances. Production analysis however indicates that the effective drainage volume, post stimulation is significantly smaller than what is observed with MS.

The objective of the cased uncemented MFHW was to achieve improved productivity over the standard cased cemented horizontal well design. The hypothesis was that the CUC wellbore would have improved connection to the reservoir and the natural fracture system existing within the target shales. In addition, the CUC well would benefit by increased reservoir contact and connection to fractures created from offset wells on the pad. The first experimental well was drilled on Nexen's 18 well pad, completed in 2012. A swellable packer system was conveyed as part of the casing string to isolate each hydraulic fracture stage. A second generation cased uncemented well with mechanical packers was tested in 2013.

This paper will discuss how the conceptual model of this new technology can be translated into an analytical model by guiding the workflow with drilling, completions and reservoir understanding and how the surveillance data such as MS, production logs, and tracers validate the process along the way.

This approach allows generating production forecasting and reserves estimates of this new technology allowing economics to be run and decision to go forward to be made. Some of the design considerations and production indications will be addressed, concluding with a discussion of the results.
Understanding Fracture Geometry of the Canadian Horn River Shale Gas via an Unconventional Complex Fracture Propagation Model in Multi-Staged Pad with 9 Horizontal Wells
Authors: Virues Claudio , Shimamoto Tatsuo , Kuroda Shintaro
Published: October 2015

Hydraulic fracturing in shale gas reservoirs has often resulted in complex fracture network growth, as evidenced by microseismic monitoring. The nature and degree of fracture complexity must be clearly understood to optimize stimulation design and completion strategy. Unfortunately, the existing single planar fracture models used in the industry today are not able to simulate complex fracture networks.

A recently developed unconventional complex fracture propagation model is able to simulate complex fracture network propagation in a formation with pre-existing natural fractures. Multiple fracture branches can propagate simultaneously and intersect/cross each other. This paper presents an integrated operator, non-operator and service provider's approach to optimize future hydraulic fracture design by fully integrating all the data captured in the Canadian Horn River shale.

Based upon insight from the study, which was initiated by the non-operator, continued by the operator and supported by the service provider in two different countries, the operator and non-operator needed to make more informed design decisions and understand the interaction between the shale, the hydraulic and pre-existing natural fracture network and reduce costs.

Data were captured from reference vertical wells and a multi-well pad. The data incorporated into the study included geophysical, geological, petrophysical, geomechanical and engineering such as dfit (small volume of water pumped into target formation) derived fracture closure pressure, production and pressure data from the horizontal wells in the pad. A generation of 2D natural fracture network is also included in the paper by defining natural fracture parameters such as length, orientation, spacing, friction coefficient, cohesion, and toughness which are almost entirely validated using lab data and geomechanical interpretation.

The complex hydraulic fracture simulation results calibrated with microseismic and fracturing treatment data were incorporated into a shale gas, numerical simulator and further calibrated with current production history of the candidate multi-wells. The results of the hydraulic fracture, natural fracture and reservoir models were utilized to understand the fracture propagation mechanism in the Canadian Horn River shale gas formation.

As a result of the project, the team is now able to run different hydraulic fracture design scenarios and assess the impact that each key design parameter has over the candidate well's long term production using a numerical simulator with a unique gridding process. Based on these findings, the operator and non-operator now have an insightful tool that could be used as the building block for future optimization of the fracture design
Lithological Controls on Mechanical Anisotropy in Shales to Predict In Situ Stress Magnitudes and Potential for Shearing of Laminations During Fracturing
Authors: Glover Ken , Bozarth Troy , Cui Albert , Wust Raphael
Published: October 2015

Accurate and repeatable assessments of in situ stress magnitudes and orientation in unconventional reservoirs can be complicated by the heterogeneous, inelastic, and/or anisotropic mechanical properties of these rocks and their complex history of burial and diagenesis. The associated vertical and lateral variation in pore pressure and stress through the target zones and bounding intervals can further complicate this effort. For these reasons, some additional factors need to be considered beyond the typical workflow of determining closure stress from standard mini-frac data and using this data to calibrate log derived stress profiles. We present some case study examples from hydrocarbon-producing shales where a more rigorous analysis of the mechanical properties of the shale has allowed a more accurate and repeatable assessment of in situ stress and potential for lamination shearing. Horizontal fracture growth through shear activation of bedding-parallel fabric can be a preferred fracture propagation mechanism in these shales and this behavior can be diagnosed by this improved workflow. In one case study example, in the tight gas Montney siltstone of Western Canada, shear strength anisotropy is shown to be very significant, with bedding parallel shear cohesion less than 10% of the bulk rock cohesion. For such situations it can be shown that shear fracturing of laminations is likely. It has been demonstrated through pressure transient analysis of minifrac injection and flowback data that this can be diagnosed. Many fracturing related mechanisms are also stress dependent and their understanding requires assessment of all in situ stress magnitudes, not just minimum horizontal stress. An improved method of analyzing these stress magnitudes and fracturing mechanisms is described through anisotropy measurements in core samples and a micro-mechanical understanding of the rock fabric. In this way, a petrophysical relationship can be established between anisotropy parameters and rock properties.
A Comprehensive Approach to Sweet-Spot Mapping for Hydraulic Fracturing and CO2 Huff-n-Puff Injection in Chattanooga Shale Formation
Authors: Vinassa M. , Cudjoe S. E. , Gomes Joao Henrique , Ghahfarokhi R. Barati
Published: October 2015

Devonian-Mississippian Chattanooga shale plays in North America are categorized as unconventional reserves with potential hydrocarbon resource accumulations. Unlike Chattanooga shale in the Appalachian region, less effort has been dedicated to its correspondent in the Ozark region. The ultra-tight nature of the formation causes fast decline of the production and small recovery factors. Application of EOR techniques such as CO2 flooding, among other techniques, can potentially improve the recovery of Chattanooga reservoirs. Characterization of these reservoirs is therefore an essential step to fully understand the associated complexities of the reservoir as well as to evaluate the economic viability of their exploitation. This paper therefore presents a fully integrated characterization at multiple scales including petrophysical, geophysical and geological evaluation, geomechanical and geochemical analysis of the black shale sequence in Sumner County, Kansas. Multi-scale dataset for this regional characterization is obtained from laboratory measured petrophysical parameters, well-log measurements as well as post-stack depth (PoSDM) seismic data.

Chattanooga shale in Sumner County has an average TOC of ~2.26 wt. % in the middle shale member with additional organic porosity of 5% and a vitrinite reflectance (Ro %) of 0.62. It is classified as a shale oil resource with OOIP of 4 MMbbl. Petrophysical correlations developed at wellbore vicinity were trained with artificial neural networks (ANNs) and correlated with seismic to provide lateral distribution of such properties farther from the wellbore. Moreover, due to the heavy reliance of unconventional shale plays on fracture network for improved flow conditions, fracture models were developed based on the mineral-brittleness as well as the fracture toughness. Consequently, a complete study based on compositional numerical simulation was conducted to analyze the potential of CO2 as an EOR technique, together with an evaluation of the impact of reservoir and fracture parameters in the well productivity potential. Subsequently, an economic optimization process was also formulated to obtain the best gas injection design for the highest Net Present Value (NPV). The cumulative oil was notably observed to increase by the use of the optimum injection design. Moreover, the huff-n-puff injection of CO2 proved to be a viable option by increasing the final oil recovery from 10% to 53% using optimal parameters.
Viking Stimulation: Case History
Authors: Fyten Glen C. , Taylor Robert S. , Price Darren
Published: October 2015

This paper presents case history results documenting the impact of changes to oil and water production in the Viking formation. This body of work applies in general to stimulation of the Viking as well and potentially other formations with high clay content. By understanding which variables have had the most impact on Viking production, it is possible to more effectively design future stimulation treatments. Some areas that previously lagged in production have now become the best producing Viking assets.

The areas studied were Red Water, Plato, and Dodsland. The wells studied were drilled horizontally using cemented casing. Hydrajet perforating was used for each fracture stage. The fracturing treatments were pumped through coiled tubing at a typical rate of 1.5 m3/min, or less using inflatable packers above and below the desired set of perforations to provide isolation. Typical fracturing treatments used 7 tonnes of 16/30 proppant and were placed using a borate crosslinked guar fluid system.

The primary design changes that have led to these improvements in production include the following: Control of clay fines migration, given that clay content in the Viking formation can exceed 50 vol%.Control of clay swelling.Prevention of paraffin precipitation caused by injected fracturing fluids having a temperature below the cloud point of the wax in the crude.Paraffin crystal structure modification to help mitigate production issues associated with any precipitated paraffin.Use of larger proppant sizes, higher proppant concentrations, and more aggressive proppant schedules.Optimization of fracture size and spacing. Because this has been the basis of much of the success in the Viking formation in recent years, a detailed discussion follows.
Production Trends From The Exploitation of Horizontal Completions in the Upper Cretaceous Formations of the Powder River Basin: A Look Back on Five Years of Development
Authors: Ruhle William , Orth Jon
Published: October 2015

The Powder River Basin in Wyoming has been exploited for the production of oil and gas for several decades. The development of horizontal drilling combined with large volume multi-stage hydraulic fracturing has initiated a new era of oil and gas production. More than 900 horizontal wells have been drilled in the Upper Cretaceous reservoirs of the Powder River Basin. Oil and gas producers often target more than one formation within any given acreage position. The focus of development has been in the Frontier Formation, the Turner sandy member, the Shannon and Sussex sandstone members of the Cody Shale, and the Parkman sandstone member of the Mesaverde Formation, along with the Niobrara Formation as an oil resource play.

This paper presents a historical review of the completion designs and production trends from horizontal wells completed in the Upper Cretaceous formations. With a focus on multistage completions, well performance indicators are used in conjunction with a spatial sampling algorithm to identify dominant production influences attributed to completion and stimulation design.

Using public records, a database was created, cataloging a completion metrics, including lateral pay length, fracture stage spacing, mass and type of fracture proppant, volume and type of fracturing fluid, and current production records. Correlations between fracture treatment design and hydrocarbon production are provided for each formation. Production type curves, initial production rates, and effective decline rates are presented for each formation. Geospatial trends in hydrocarbon properties, such as gas-oil ratio (GOR) and oil gravity are provided.

The catalog of data and correlations provides a useful reference for exploring or developing acreage within the basin.

Optimizing completion programs can be fast-tracked through the analysis of preceding completions and early time production indicators.
Insights into Surfactant Containing Fracturing Fluids Inducing Microcracks and Spontaneously Imbibing in Shale Rocks
Authors: Xu Liang , He Kai , Nguyen Christina
Published: October 2015

Surfactants are typically added into fracturing fluids to assist flowback and/or enhance oil and gas production from liquids-rich shale formations. Two primary benefits that can be overlooked are the potential capability of surfactants to initiate microcracks near primary fractures and spontaneous imbibition farther into the formation rocks. With the additional initiation of microcracks and access to hydrocarbon reserves, initial production can be enhanced and production declines, over time, can also be mitigated.

In this study, new mechanisms for surfactants to initiate microcracks and accelerate crack growth are proposed in which the speed of microcrack propagation could be controlled by the rate at which surfactant is advected to the crack tip by means of induced Marangoi flows (Vella et al. 2006). The accelerated crack growth is related to a decrease of the crack surface energy enabled in the presence of surfactant.

On the other hand, a new mechanism has been previously proposed for increasing the contact area between fracturing fluids and the matrix. The working hypothesis is that a surfactant, when properly tailored to treatment fluids, can spontaneously spread in the matrix and access additional hydrocarbon reserves.

The data indicate that fracturing designs could be further optimized by using a surfactant to activate more cracks. The shut-in time immediately after fracturing also could be crucial for enhanced well productivity. An extended shut-in time could result in the additional initiation of microcracks, farther penetration of fracturing fluids into the matrix, and greater oil recovery in liquids-rich shale plays.
Evaluating the Diagenetic Alteration and Structural Integrity of Volcanic Ash Beds within the Eagle Ford Shale
Authors: Calvin Christina , Diaz Helena Gamero , Mosse Laurent , Miller Camron , Fisher Kevin
Published: October 2015

Ash deposits are found interbedded within organic mudstones such as the Vaca Muerta, Niobrara and Eagle Ford shales. Alteration of ash deposits interbedded within mudstones and shales have presented challenges for completion and production including pinching of fractures and swelling upon contact with drilling and completion fluids. This paper will review the mineralogic and petrologic variations in altered ash beds found within the Eagle Ford and examine the impact these chemical and physical properties can have on completion. The paper will also present a methodology for detection of ash beds using high-resolution measurements. Understanding and detecting the mineralogic variation between the altered ash beds will enable better completion and minimize risk during production.
A Study of Mercury Intrusion on Montney Formation Rocks and How It Relates to Permeability
Authors: Salimifard B. , Ruth D. W. , Nassichuk B.
Published: October 2015

The Montney Formation, a tight unconventional reservoir in Western Canada, has been explored for the past two decades and over the last 10 years has moved towards being a primary exploration target. Qualitative and quantitative petrophysical analysis of the Montney Formation has always been a challenge to researchers. Reservoir characterization is generally hindered by lab-based methods for permeability estimation, proper estimation of the pore size distribution and development of correlations between the rock properties and hydraulic flow.

This report examines results from permeametry, mercury porosimetry, helium pycnometry and scanning electron microscopy (SEM) images performed on 53 samples of the Montney Formation to understand the complicated pore network structure of the rock and study the predictive power of a permeability prediction model.

Pulse-Decay permeability is measured on cores at effective reservoir pressure. Crushed samples are used to obtain mercury capillary pressure, pore size distribution curves, GRI and mercury porosity and matrix permeability. SEM images are used to study pore development and porosity as well as investigating the presence of microfractures. The permeabilities of these samples range from 10 nanodarcies to 0.1 milidarcies and porosities range from 2-10 percent. Due to high surface intrusions in the mercury porosimetry tests, extraction of pore size distributions and capillary pressure curves are problematic and cut-offs are applied based on the derivative of the capillary pressure curve to help understand the complicated pore network of the rock and correlate it with permeability.

This study shows that mercury porosimetry results can be used to categorize the rocks into subcategories for further analysis. Different methods correlating rock properties to permeability are examined. The results specifically indicate that pulse-decay permeability is influenced by over-burden pressure and the presence of microfractures and that the appropriate pore diameter shows consistent correlation with the derivative of the capillary pressure curve.
Miscible CO2 Simultaneous Water-And-Gas (CO2-SWAG) Injection in the Bakken Formation
Authors: Gong Yanbin , Gu Yongan
Published: October 2015

In this paper, miscible CO2 simultaneous water-and-gas (CO2-SWAG) injection in the tight Bakken formation was experimentally studied. The effective viscosities of high-salinity water and supercritical CO2 mixtures with twelve different water volume fractions were measured at the actual reservoir conditions by using a capillary viscometer. A total of six coreflood tests with four different miscible CO2-EOR schemes were conducted in the tight reservoir core plugs collected from the Bakken formation (Canada). It was found that the measured effective viscosity of the saline water-CO2 mixture was increased with the water volume fraction and can be reasonably modeled by using the Arrhenius equation. The coreflood test results indicated that the miscible CO2-SWAG injection with an injected water-gas ratio (WGR) of 1:3 in volume had the highest oil recovery factor (RF). The miscible CO2 water-alternating-gas (CO2-WAG) injection achieved a slightly higher oil RF than that of the miscible CO2 secondary flooding, whereas the miscible CO2 tertiary flooding after mature waterflooding had the lowest oil RF. In addition, the WGR showed strong effects on the fluid production trends of the miscible CO2-SWAG injection. A water bank might be formed ahead of the water-CO2 mixture in the miscible CO2-SWAG injection with a higher injected WGR of 1:1 or 3:1. Furthermore, the mobility ratio of the injected fluid(s) to light crude oil was calculated based on the measured steady-state flow rate and pressure gradient in each coreflood test. In comparison with water or CO2 alone, the water-CO2 mixture had a lower mobility in the tight reservoir core plugs. Hence, the highest oil RF of the optimum CO2-SWAG injection with the lowest injected WGR of 1:3 was attributed to a substantially weakened waterblocking effect and a well-controlled water-CO2 mobility.
Modeling the Kerogen 3D Molecular Structure
Authors: Zhang Zhenyu , Jamili Ahmad
Published: October 2015

During the past decade, there has been a surge in the production of shale oil and this trend is expected to continue in future due to the abundant shale oil reserve. Currently, one main issue with shale oil production is the low primary recovery factors still less than 10%. Therefore, efficient enhanced oil recovery methods are highly desired to improve shale oil recovery. As an essential component of shale, kerogen plays a key role in generation, adsorption, storage and migration of hydrocarbons in shale as well as the geomechanical properties of shale. On the other hand, during the shale oil extraction process, shale oil can be produced from kerogen by pyrolysis, hydrogenation, or thermal dissolution reactions. The basis to improve the efficiency of both recovery and extraction processes is to establish and clarify the molecular structure of kerogen. Previously, some 2D molecular structures of kerogen have been proposed based on some characterization techniques, such as nuclear magnetic resonance (NMR) and mass spectrospcoy. However, the physical and chemical properties of kerogen are essentially determined by its 3D stereochemical molecular configuration.

In this work, according to the 2D molecular structure of Green River oil shale kerogen from literature, a 3D solid state model of kerogen was built based on molecular dynamics(MD) simulation method. The kerogen of Green River oil shale is a mixture of seven molecules that are held together by physical adsorption mechanism. This kerogen belongs to type I based on O/C (0.026) and H/C (1.57) ratios. An adsorption method was applied to combine the seven molecules together. By changing the adsorption sequences of the seven molecules, a total of 24 possible 3D nanocluster models of kerogen were obtained. Then the 3D nanocluster structure with the lowest energy was further applied to build the solid state model of kerogen at 298k under 1 atm based on a MD simulation method. The final 3D solid state model of kerogen was used to calculate the density, mechanical properties, NMR, IR and Raman spectra of kerogen. The theoretical results agree well with the experimental data. The density from the 3D structure was calculated as 0.968 g/cm3 which falls in the range of experimental results from 0.95 to 1.45 g/cm3. The calculated Young's modulus, Poisson ratio, compressibility, bulk modulus and shear modulus are 3.50 GPa, 0.25, 370.64 TPa-1, 2.63 GPa and 1.37 GPa respectively that matches the experimental results very well. The calculated spectral data are also in accord with the experimental results. These results will help us better understand the physical and chemical properties of Green River oil shale kerogen. Moreover, the calculated properties of kerogen can be applied to implement new techniques or improve existing methods for enhancing oil recovery from shale oil resources.
A Comprehensive Approach to Rate-Time Production Analysis for Unconventional Resources
Authors: Cox S. A. , Lee J. , Sutton R. P. , Cox J. A.
Published: October 2015

Decline curve analysis in unconventional reservoirs is challenging due to the extremely low reservoir flow capacity coupled with the completion techniques and production practices used to achieve economic rates. The primary flow regimes for these wells include transient bilinear flow, transient linear flow, boundary-influenced flow and possibly long-term linear flow. It is commonly believed that the dominant flow regime in unconventional developments will be transient linear flow; however, boundary-influenced flow may be even more important. Classical decline curve analysis techniques are applicable only during the boundary-influenced flow period. Frequently, a hyperbolic form equation is utilized and this practice used by the industry over the entire life of the well results in excessively high decline exponents which can lead to optimistic forecasts of future performance. This technique can be improved for unconventional plays by imposing limits to the final decline. However, current methods to constrain the final decline are based on historical vertical well performance and rules of thumb which introduce a high degree of uncertainty. A number of these plays have now reached a level of maturity that will allow characterization of their long term decline performance. This paper presents a comprehensive technique to analyze production history using a flow regime based workflow to guide classic decline curve analysis. The technique identifies the onset of boundary-influenced flow and thus provides a consistent approach to evaluate late time decline characteristics which will improve the forecast results. In addition to providing guidance for decline curve analysis, the proposed workflow can also be used to evaluate completion efficiency by relating the time to boundary-influenced flow to the stimulated reservoir volume. The practical application of this this technique will be presented using field studies of active unconventional developments.
Managed Pressure Drilling Significantly Reduces Drilling Costs on Extremely Challenging UltraHT Wells in the Gulf of Thailand
Authors: Loux Fabrice , Bunyak Michael John , Kongpat Nitipong , Pattanapong Kamolchai , Eagark Pasuk , Rubianto Irwan , Gallo Fernando , Intravichit Jittipong , Charnvit Kerati , Prasetia Andi Eka , Houng N. H.
Published: October 2015

PTTEP in the Gulf of Thailand faced costly challenges while conventionally drilling several narrow operating window ultra high temperature (ultraHT) wells with formation temperature up to 220°C (428°F). In the ultraHT sections, the operator encountered serious ballooning issues that resulted in severe non-productive time (NPT) and difficulty reaching well total depth (TD). Additionally, formation pressure uncertainty in the steep pressure ramp region posed additional drilling challenges due to high risk of influxes.

PTTEP decided to utilize managed pressure drilling (MPD) to overcome the complex ultraHT wells. The strategy involved designing a hydrostatically underbalanced mud weight to prevent ballooning and to enable optimal drilling flowrates. The automated MPD was used to continuously maintain bottomhole pressure (BHP) above pore pressure to avoid influxes. Furthermore, the MPD system was also used to safely identify formation pressures by performing static flow checks (SFC). Dynamic formation integrity tests (DFIT) and dynamic leak-off tests (DLOT) conducted while drilling accurately identified the losses limit and ballooning gradient. At well TD, special rollover procedures were implemented to displace trip mud weight in order to safely control the well prior to pulling out of hole, taking into account extreme thermal effects on bottomhole pressure (BHP) reduction.

PTTEP was able to drill through the narrow operating window and avoid problems associated with typical ultraHT condition, including ballooning, loss and influx events. Moreover, MPD allowed the operator to drill efficiently while identifying the actual drilling window to establish wellbore pressure boundaries. Importantly, the operator was able to log the well to obtain the necessary geological data. As a result, the operator cut well costs by 50%, a total of USD 5 million, and saved 20 days of drilling time.

The paper will share the success story of MPD application in drilling challenging ultraHT wells in the Gulf of Thailand. The paper will describe the drilling solutions to solve the well problems and the lessons learnt as part of knowledge sharing.
Significant Initiatives for Managing Emergency Response at Drilling Rigs in Remote Areas - Smart Alert System (SAS)
Authors: Al-Shatti Ahmad , Al-Rakdan Abdulwahab , Al-Khaldy Ali
Published: October 2015

Kuwait Oil Company is the premier Oil & Gas Company in the Gulf region involved in exploration and production of oil & gas reserves. The Company is one of the subsidiaries of Kuwait Petroleum Corporation, State of Kuwait. In line with the Company strategy to improve its production capacity from current 3.0 Million BPD to 4.0 Million BPD, the company deployed many on-shore drilling rigs on a fast track basis during past two years. Present Rig Fleet includes 25 deep drilling rigs and 60 development drilling & work over Rigs. The Company has established the HSE Management System and procedures based on the international standards to focus on the health, safety of workers and environmental protection.

Since majority of Rig fleet is deployed in desert remote areas, where there is a challenge in response time during any emergency situation. Various Initiatives and improvements programs were implemented to avoid such emergency at first place, which resulted in enhanced HSE performance especially the LTIFR as well, and in addition, Company has adopted the latest technology called Smart Alert System (SAS) for emergency response especially for drilling rigs working in remote desert areas. This system is based on GPRS, SMS, GPS protocol using GIS map enabled Tablet PCs.

The presentation discusses the experience of Kuwait Oil Company in enhancing the performance overcoming all HSE challenges by implementing various intitative and sharing the best practices adopted for emergency response for Drilling Rigs operated in remote desert areas.
Application of Optimized Particle-Sized Lightweight Cement Technology to Improve Integrity on Surface Casings in Myanmar
Authors: Olutimehin Kunle , Jia Zhang Xua , Voon Eric
Published: October 2015

One of the main challenges of drilling in the Central Andaman Sea offshore Myanmar is the mitigation of overall well integrity risk arising from weak top-hole formations. On a well drilled by one operator, conductor integrity was lost due to cratering and loss circulation while cementing which eventually led to having to re-spud the well. Almost all the offset wells drilled by the operator in the same field experienced losses in the top section interval.

To meet integrity objectives for both exploration and development wells, the cementing strategy in certain cases must consider alternative solutions in addition to conventional Class G cement. In a recent project executed for one operator the cementing philosophy for the entire surface sections therefore had to be fine-tuned to incorporate the proven Optimized particle-sized distribution methodology.

A proprietary coarse material made from glass beads was introduced as part of the slurry design, being used for the first time in Myanmar to further improve cement properties. On the development wells the optimized design called for pumping 10.5ppg High-performance Light-weight cement (HPLWC) lead slurry, together with a standard Class G tail.

To meet operational integrity objectives, planning and risk assessments were put in place by the service company and the cementing programmes were developed to incorporate necessary mitigations against the identified risks. Plans were put in place to handle the implicit logistics requirements. Careful attention was paid to the execution given the downhole pressure sensitivities, all slurries were mixed and pumped with a degree of relative precision.

This paper summarizes the design and implementation of the cementing operation which contributed positively to meeting well integrity objectives. Apart from operational success, expectations which hitherto factored in possibility of top-up jobs were exceeded; for the exploration well the critical zones were covered with good returns to seabed observed on all the cement jobs as monitored by ROV. Hard cement were tagged and drilled out from the shoe track in each case and well operations progressed without any loss of integrity issue.

The paper aims to demonstrate that incorporating technology can help to improve well delivery and reduced lost time. Approximately, 18 cement jobs have been executed on the project - all successfully done. Out of these 4 top-hole cement jobs involved the use of the High-performance Light-weight (HPLWC) technology described in this paper.
A Comprehensive Downhole Capillary Surfactant Injection Screening & Optimisation for Liquid Loaded Gas Wells
Authors: Andrianata Satria , Susanto Agung
Published: October 2015

Depletion of the reservoirs leads to a decrease in field production rate. Wells production rate continue to drop below the minimum critical velocity, at which point the liquid that was previously carried upward by the gas begins to fall back. The produced liquid accumulates in the well creating a static column of liquid, therefore creating a backpressure against formation pressure and reducing production until the well ceases production. Down hole Capillary Surfactant Injection (DCSI) is installed on the wells to overcome the liquid loading symptom by generating foam, thereby reducing the surface tension, lowering the fluid density, and lowering critical rate. This paper discusses the improvement to obtain higher success ratio of DCSI installation project on the observed field. Analysis and improvement is done to improve the success of DCSI installation through a comprehensive wells screening, continuity laboratory test, and field optimisation. The screening including the selection of liquid loaded wells & laboratory test (foam test, pH, and salinity test) were corrected with the actual temperature to obtain an accurate foam performance. Correlation is generated to correct the effect of foam build rate and decay rate against critical parameters. Validating well performances with the results of laboratory tests is conducted by continuously field optimisation. The laboratory test is significantly important to screen DCSI well candidate. Surfactant concentration, temperature, & condensate content are critical variables for foam build up and decay performances. Uncertainty variable and un-matching well performance previously not assessed can be reduced by these improvement steps, thus increasing the success ratio DCSI project. The improvement DCSI screening proposed is used as a reference to start the DCSI project to obtain higher success ratio.
Drill Site Surface Facilities Readiness: Systems Improvement through Use of IT (An Upstream Oil & Gas Company's Approach)
Authors: Nath U. , Phookan J.
Published: October 2015

Getting a drill site ready on time for drilling with the least idle time to its resources (drilling rigs and rig related manpower) was becoming a major constraint to the Company's achieving its annual operational targets. On an average the Company has to drill at least 50 locations in a year. Multiple departments are involved in the entire process of getting a drill site ready for drilling with multiple activities, some independent and some dependant, having to be carried out by the concerned departments before the final objective can be achieved.

It was seen that the existing system of monitoring and reporting of the pre-drilling status of sites was not effective and hence there was an urgent requirement for an IT based on-line monitoring system to be implemented for ease of monitoring, transparency, better review and decision making.

Treating each of the drill sites as a project by itself, which needed to be monitored closely by the use of a system with multiple data input and reporting channels and having the ability to generate various reporting formats meant that there would be multiple projects required to be monitored at any given time.

By implementing an integrated enterprise project management solution having multiple users the Company was able to meet its requirements.
Integrated Static and Dynamic Modelling Workflow for Improved History Matching and Uncertainty Modelling
Authors: Chong E. E. , Wan Mohamad W. N. , Rae S. F. , Lim L. , Flew S.
Published: October 2015

Traditionally, the history matching process is done only on the dynamic model, without any direct update to the geological (or static) model. As a result, geological uncertainties are not fully evaluated in the dynamic model. Non-integration of static and dynamic modelling results in either too much time being spent modelling detailed geological phenomena that have little impact on the dynamic behaviour of the reservoir, or, conversely, important geological and petrophysical parameters being misrepresented or missed out which may have significant impacts on the overall field development strategy.

Ideally, if any updates to static parameters are required as result of history matching in the dynamic model, these changes should be reflected directly in the static reservoir model, thereby ensuring consistency between the static and dynamic models.

In this paper, a workflow is presented where both the static and dynamic modelling software packages are integrated as part of the history matching process. This workflow involves input parameters being adjusted in the geological model directly. Uncertainty analysis tools are used to obtain multiple history-matched models, which results in an order of magnitude increase in speed compared to traditional history-matching processes.

Not only will this methodology result in improved history-matched models with a wider range of production forecasts being captured, but more importantly, it will result in better understanding of the static and dynamic uncertainties and their interdependencies, leading to a more informed decision-making process with regards to overall field development. In addition, this methodology offers a platform where the subsurface professionals involved in reservoir model construction and simulation processes can focus their efforts on improving reservoir characterization and identify areas that require further data acquisition or improvement.

This paper also describes how the workflow was successfully applied to a recently developed, producing and waterflooded oil field in South East Asia, and eventually delivering an optimized reservoir model for reservoir management and a probabilistic approach to production forecasting.