bluuebunny/crossref_metadata_2025 huggingface dataset:
Estimating Sand Production Volume in Oil and Gas Reservoir
Authors: Ray P. , Rijken M. , Cameron J. , Jones C. , El-Fayoumi A.
Published: October 2014

Sand control techniques are widely used in industry to prevent sand production. However these techniques significantly increase completion cost and complexity as well as can potentially impact production and field economics. Hence it is preferred not to install sand control if one can be assured that the sand volume which will be produced is manageable. However, there are no tools or workflows which can consistently and accurately predict the expected sand volume and timing over the life of the field without a large range of uncertainty.

In this study, sand production characteristics were tested in three different sandstone outcrops under varying fluid flow conditions. The test results show different sanding behavior for brine, oil, and gas flow. Samples tested with brine fail catastrophically when stress is applied which slightly exceeds the onset of sand production stress. Samples with gas flow produce small amounts of sand even when the stress significantly exceeds the onset of sand production. The test results also demonstrated the importance of drawdown pressure on sand production, where an increase in drawdown has the potential to significantly increase the sand production. Subsequently both numerical and empirical models were developed to estimate and predict sand production volume. These models have been able to model field sand production cases reasonably well
Modelling Heavy Oil Viscosity During Thermal Stimulation Using the Free Volume Theory
Authors: de la Porte J. J. , Zimmerman R. W. , Kossack C. A.
Published: October 2014

Large errors in oil viscosity predictions result in large production rate errors during numerical simulation, due to a first-order dependency of flow rates on viscosity. Questions that arise during thermal simulation studies of heavy oil are (1) which viscosity-temperature model could be sufficiently well based on molecular physics such that viscosity prediction, as a function of temperature, would be possible if only oil composition is available; (2) in which temperature range do viscosity predictions need to be most accurate so as to ensure most accurate recovery predictions – the high or the low end? This work will provide simulation engineers with additional tools and information to address these questions, and more accurately model production of heavy oil under thermal stimulation, by providing a viscosity model based on physical properties of molecular structure and thermodynamic behavior, and additionally, will show that the priority temperature range depends on the thermal recovery method.

The Free Volume Model (FVM), based on the concept of the ‘available free space to which a molecule can move under shear stress’, is applied in this work to three different heavy oils to calculate viscosity as a function of temperature. The model was first extended for application to extra-long chain molecules up to C64H130 by de la Porte (2012) and de la Porte and Kossack (2014); the present work will provide users with guidelines to estimate the FVT molecular characteristics for a resin-asphaltene heavy pseudo-component.

Furthermore, the range of temperatures at which accurate viscosity prediction is essential for more accurate oil recovery predictions is investigated for various recovery methods, such as cyclic steam stimulation (CSS), line-drive steam stimulation (SLD), and steam-assisted gravity-drainage (SAGD). Analytical models are used to predict the sensitivity to the viscosity error in a specific temperature range, followed by numerical simulation to confirm the findings.

This research, the first to extend the Free Volume Theory to heavy oil components, will contribute towards more accurate numerical simulation of heavy oil reservoirs.
Measuring Drilling Standardization Using Approximate String Matching
Authors: Montgomery Justin B. , O'Sullivan Francis M.
Published: October 2014

Standardization of drilling procedures is a key element for success in the development of unconventional oil and gas fields today. We propose approximate string matching as a data analytic technique that can be used to measure standardization across wells in a field. We describe the implementation of approximate string matching, providing details of how it can be contextualized for oil and gas drilling using operation codes, and how results can be normalized to allow for comparison between disproportionate sequences of operations. We use this technique to develop a measure for operational variability, the first objective metric for evaluating and comparing the rate and consistency of standardization across different wells, sections of wells, and rigs, informing decision-making based on the existing large streams of feedback from field operations. We provide examples of operational variability using analysis of data from about two hundred horizontal wells drilled by a single operator in a major North American unconventional field, and develop the concept of the "standardization curve" from this to demonstrate the importance of this metric in understanding learning and movement along the "learning curve" during a drilling campaign. Additionally, we outline some specific ways that these approaches can be used to automate the data-driven comparison, disaggregation, and assimilation of field learning to better manage improvement within drilling campaigns. This tool provides a foundation upon which future data analytic and machine learning techniques can build, developing learning programs for "smart" oil and gas fields that make better use of available data to enable rapid adaptation and greater overall drilling efficiency.
Evaluation of Reservoir Connectivity and Hydrocarbon Resource Size in a Deep Water Gas Field Using Multi-Well Interference Tests
Authors: Ohaeri Charles U. , Sankaran Sathish , Fernandez Juan
Published: October 2014

The Prosperidade field offshore Mozambique is a large deep water gas field with three main fan reservoir complexes. The field extent covers an area about fifty kilometers long and ten kilometers wide. As part of the field appraisal and development process, an extensive Drill Stem Test (DST) and Multi-Well Interference program, involving several strategically placed wells, was conducted to assist in evaluating reservoir connectivity and original gas in place. This paper presents the interference test program, First, the objectives, design methodology and criteria are discussed. Next, we present the test conduct and the methods used to retrieve interference pressure data at observation wells over time. We also discuss the challenges associated with measuring small pressure changes (< 0.5 psi) in the presence of tidal effects as well as the methods we have used to handle noise and gauge pressure drift. Finally, we present the methods used to evaluate reservoir connectivity and gas in place.

In analyzing the interference pressure data, we have used both analytical methods and numerical reservoir simulation. More importantly, we have used a new material balance technique to directly calculate the original gas in place. This method uses rock and fluid data and the small changes in pressure at the observation wells. Therefore, errors and uncertainties in the input or measured data will affect the results. To account for this, the Monte Carlo simulation approach was used to provide statistics on the magnitude and range of the calculated original gas in place.

The results of the work have helped us understand the connectivity of the various fan reservoirs over several kilometers. This has been an important contribution for both field development and reserve certification
First Successful Filtercake Damage Removal Treatment Utilizing In-situ Nitrogen/Heat Generating system for Relatively Heavy Oil Wells
Authors: Al-Taq Ali A. , Al-Haji Habeeb H. , Saleem Jaffar A.
Published: October 2014

Nitrogen/heat generating system (N/HGS) is a thermal-chemical method comprising huge amounts of heat and nitrogen gas generated by reaction between two nitrogen-containing aqueous salts, ammonium chloride and sodium nitrate. The inherent properties of this system make it a good additive in matrix acid stimulation and clean-up treatments for heavy oil wells. The generated heat tends to reduce the oil viscosity, thus enhancing oil mobility while the generated nitrogen gas will reduce hydrostatic pressure of the oil column. Both actions will help the reservoir to better cleanup.

Lab results showed that N/HGS was effective in removing oil-based mud filtercake damage. Application of N/HGS cleanup fluid in HP/HT filter press cell was associated with an increase in pressure of more than 100 psi and in temperature of nearly 40°C. An optimized N/HGS formulation was very effective on filtercake removal; nearly 81% of flow efficiency was obtained. The N/HGS formulation contains in addition to the basic nitrogen-containing salts an organic acid, an emulsion breaker and a viscosity reducer. The organic acid, acting as a reaction catalyst in N/HGS, is also proposed to dissolve bridging material presents in filtercake, calcium carbonate.

Application of this system, for first time in Saudi Arabia, to remove oil-based filtercake damage from a sandstone horizontal well was very successful. The N/HGS components were pumped in a way to be mixed in the wellbore of the horizontal section. Coiled tubing was used to pump one component while the other component was pumped through the annulus. The reaction of N/HGS components was associated with generation of huge heat as detected by the Distributed Temperature Survey (DTS) which showed that reservoir temperature increased from 153 to more than 300°F. Following the N/HGS treatment, the dead well was able to produce naturally with a competitive production rate compared to offset wells treated with conventional clean-up fluids.
Well Spacing Optimization of Liquid Rich Shale Plays Using Reservoir Simulation
Authors: Eburi S. , Padmakar A. S. , Wilson K. , Banki R. , Wardell I.
Published: October 2014

In recent years, liquid rich shale plays have become the focus of many operators developing unconventional resources. After years of drilling single wells in a section to hold leases, companies are facing key field development questions – what is the appropriate well spacing and what is the right development plan for their unconventional assets? Some operators have simply used a trial and error approach while others have designed and drilled pilots to test various well spacing scenarios and multiple field development strategies following an experimental design approach. Both of these methods could take significant time before conclusive results could be observed, and these field trials often involve significant capital investment to test a few combinations with the hope of inferring the optimal solution. Another key question many operators have is how does the optimal well spacing change with fluid type or with shale play? Liquid rich shale plays like Eagle Ford, Utica and Duvernay show multiple fluid gradients. Depending on which fluids a company's acreage contains, the optimal well spacing will vary as will the development plans. Therefore, it is very important to understand the effect of fluid composition on recovery and well spacing in liquid rich shale plays. In this work, a reservoir flow simulation model is built and history matched to a synthetic liquid rich shale well production history in order to predict the estimated ultimate recovery (EUR) for various well spacing scenarios. The flow simulation model incorporates dominant shale flow and storage mechanisms including multi-phase physics. Using the calibrated simulation model, a study was performed to quantify the reduction in EUR due to well interference and sensitivities to fluid composition were conducted to understand its effects on well productivity and recovery factor. Results indicate that the outlined workflow provides a reliable tool for performance evaluation of various field development strategies and that well performance and fluid composition can have a significant impact on well spacing and field development decisions.
Production Data Integration for Virtual Flow Metering
Authors: Moreno Gustavo A. , Garriz Abel E. , Badessich Matías Fernandez , Bottesi Germán L.
Published: October 2014

Real time multi-phase flow monitoring can be economically hard to implement in a well by well basis. In many cases production controls are sporadic and distributed among wells in a common collector battery where the total production is measured regularly. Under this situation a common problem is the definition of fluid rate allocation factors with those limited measurements. However there exist physical variables, such as well head pressure, that can be correlated to flow rate and are frequently available. These complementary measurements can be used to enhance fluid rate allocation. In this paper we present a model that can be used to enhance two-phase liquid production estimates using flow rate controls combined with well head pressure measurements. This model is especially well suited for over-pressured unconventional reservoirs, where the interaction between producers can be neglected and total fluid rate is highly correlated with flowing pressure. The model can be solved using techniques from operations research and is fast enough to be coupled to a real time flow metering system in large scale.
Experimental Study of Foam Generation, Sweep Efficiency and Flow in a Fracture Network
Authors: Fernø M. A. , Gauteplass J. , Pancharoen M. , Haugen Å , Graue A. , Kovscek A. R. , Hirasaki G.
Published: October 2014

Foam is consistently generated in situ in rough-walled, calcite fracture networks during experiments using surfactant-alternating-gas (SAG) and coinjection of gas and surfactant solution over a range of gas fractional flows. Boundary conditions are systematically changed including gas fractional flow, total flow rate, and liquid rates. Local sweep efficiency was evaluated through visualization of the propagation of the fluid front and compared for pure gas injection, SAG, and coinjection. Foam as a mobility control agent resulted in significantly improved sweep and delayed gas breakthrough. Gas mobility reduction factors varied from about 200 to more than 1000 consistent with observations of improved sweep. Shear-thinning foam-flow behavior was observed during coinjection over a range of gas fractional flow.
Some Fracs Are More Equal Than Others: Expanding the Use of a Complexity & Conductivity Focused Frac Design in the Williston Basin
Authors: Wright Jon , Barella Marc , Wright Chris , Weijers Leen , Riebel Tom
Published: October 2014

A novel completion approach was developed in 2010 for Central Basin Bakken wells that focused on incorporating plug & perf technology with slickwater fluids and ceramics proppant in an uncemented liner. While these jobs can be very unforgiving from an execution perspective and are more expensive to complete, production from more than one hundred wells shows that this approach is superior in comparison to conventional ball-sleeve, gel and sand completions. We believe the improved production response for this completion approach benefits from (1) creating a more complex fracture geometry through the distributed plug-and-perf initiation points and the creation of widespread complexity through high-rate large-volume low-viscosity frac jobs; and (2) placement of higher conductivity, with smaller-size and stronger proppants to more effectively prop open complex fracture networks.

Application of this design was initially limited to the Central Basin, but has recently been applied in other areas across the Williston Basin including both the poorer quality rock along the fringes of the basin as well as the naturally fractured and prolific rock on the Fort Berthold Reservation. In addition, other operators have conducted designs across the basin with a similar focus on conductivity and complexity, albeit achieved through alternate design strategies.

This paper starts with a review of completion practices for the entire Williston Basin and how they compare to a complexity & conductivity focused design. We will present multi-variate analysis results to determine which geological or completion parameter has the most impact on production response, and what design parameter gives the best "bang for the buck" in an economic evaluation of these completion and fracture design changes.
Development of a Stranded Tight Gas Field in the UK Southern North Sea Using Hydraulic Fracturing Within a Subsea Horizontal Well: A Case Study
Authors: Langford Marc , Westera Douglas , Holland Brian , Bocaneala Bogdan , Norris Mark
Published: October 2014

There are more than 100 accumulations in the southern North Sea that are flagged as stranded fields. Tight reservoirs, distant infrastructure, small volumes, and anomalous gas qualities are amongst the main reasons why these resources have not yet been developed. One of these stranded tight gas fields has been successfully developed with the use of a subsea well, horizontal drilling, and hydraulic fracturing.

The Kew structure is a northwest/southeast trending horst straddling licenses 49/4c, 49/4a, 49/5a, and 49/5b of the UK sector approximately 2 km east of the Chiswick field. The primary reservoir objectives are the Carboniferous sandstones of the Caister formation (Westphalian A). This gas field has now been developed with a singlewell that employs a combination of horizontal drilling and multistage hydraulic fracturing to achieve maximum reservoir contact in this low-permeability and interbedded structure.

The absence of data and analogue wells for the design and execution of the fracturing treatments necessitated extended injection tests prior to the execution of the stimulation treatments. To maximize the data acquired from this well, chemical tracers were injected during the stimulation treatments and returns evaluated to assess the flowback of each individual hydraulic fracture. As this was a subsea development well, all the hydraulic fracturing operations had to be performed with the rig in place. Hence, the utmost efficiency of the operations was paramount; otherwise, the economics of the project would be negatively impacted. Innovative techniques of isolation between each fracturing stage were developed to minimize the risk and decrease completion time.

The time of massive gas field discoveries has passed, and smaller developments are proving to be the future, through tying them to existing assets, to boost gas production in the North Sea and extend the life of the existing infrastructure. This challenge was successfully addressed for the Kew field by combining existing technologies and developing new techniques.
Evaluation of Fault Sealing Ability and Prediction of Fault Critical Reactivation Pressure in Water Flooding Reservoir
Authors: Hou YaWei , Zhao ChunMing , Su YanChun , Wu TingTing , Luo XianBo , Yang QingHong , Huang Kai
Published: October 2014

Fault reactivation induced by excessive reservoir water pressure in oil fields is suspected as one of the possible perpetrators that caused crude oil eruption to the surface. This can lead to significant financial losses related to environment cleanup and curtailed oil production. During fluid production and injection, changes in stress have a significant influence on reservoir behavior. Fault sealing ability is one of the key factors that control hydrocarbon preservation. If these faults are reactivated, their permeabilities will likely increase, facilitating fluid migration and potentially compromising the hydraulic integrity of the caprocks that seal the reservoir. Therefore, during a waterflooding process, it is necessary to limit the injection pressure in order to avoid fault reactivation. A traditional approach to fault reactivation prediction provides a deterministic critical reservoir pressure without proper regard to the uncertainties in the model input parameters and the predicted results. A probability distribution of the fault reactivation critical reservoir pressure provides a better means to calculate a risk weighted Expected Net Present Value for management to make better decisions on water flooding and to anticipate potential consequences.

In this study, a geomechanical model was established for the BZ Field, Bohai Bay, China. Using the geomechanical model, first, a fault seal analysis was performed and indicated that all faults were sealed in sands under initial stress and pore pressure conditions. Second, fault reactivation reservoir pressures for major faults in the field were predicted assuming a frictional sliding frictional coefficient of 0.5, which was derived using frictional faulting theory by the geological events provider for the nearby PL Field. Monte Carlo simulations were run to consider the uncertainties of frictional sliding coefficient, and especially the the minimum horizontal stress among the input parameters.
Mature Fractured Reservoir Meets the Era of Young Minds and the New Age of Technology Digital Oil Field
Authors: Jamal Mariam Abdul-Raheem , Anthony Elred , chetri HB , Ibrahim Hossam El-Din , kumar Priya ranjan , Nair Sajan , Al-Zaabi Hamad
Published: October 2014

Within a natural fractured Carbonate Reservoir a NOC's Overall production rates are constantly challenged with factors, such as high permeability streaks, poor macroscopic sweep efficiency, and low mobility ratios, all of which can dramatically impair production rates and reservoir oil recoveries.

This paper presents the experiences from managing said reservoir using traditional reservoir engineering sound practices and latest digital technologies of IDOF.

We describe in recent years how a collaborative and multi-disciplinary team implemented a series OF BEST PRACTICE reservoir-to-surface surveillance practices which include: water flood-front monitoring through wellbore resistivity and seismic methods,injector-producer connectivity mapping through tracer tests complemented with data-drive analytics, numeric and streamline simulation,Well performance and productivity watching via real-time data processing, analysis, modeling and optimization,Water flood displacement and volumetric efficiency following up through continuous reservoir shut-in pressure data capture or estimation via multi-rate testing and permanent down hole gauges installations.

Data and consistently applied work processes are orchestrated through digital technologies which include workflow management and integrated visualization, allow making well-informed, real time decisions to optimum reservoir recovery management.

These actions included the identification of various infill drilling opportunities of vertical, horizontal and multilateral wells,optimum allocation of water injection and production allowable andrecommendation for water-shut-off and water conformance jobs.✓ Post-mortem analysis of results demonstrated production increases of 33% and increase recovery expectation above 13%.✓ In closing we discuss challenges and lessons learned.
Perdido Development: Unified Fluid Model (UFM) for Integrated Production System Modeling (IPSM)
Authors: Galvan D. , McVinnie G. , Dindoruk B.
Published: October 2014

The Perdido development is one of the most complex deepwater projects in the world. It is operated by Shell in partnership with Chevron and BP. It currently produces hydrocarbons from twelve subsea wells penetrating four separate reservoirs. The properties of produced fluid vary per reservoir as well as spatially. The producing wells display a relatively wide range of fluid gravities, between 17 and 41 °API, and producing Gas Oil Ratios (GOR), between 480 and 3000 scf/bbl. The fluids produced from the subsea wells are blended in the subsea system and lifted to the topsides facilities via five seabed Caisson Electrical Submersible Pumps (ESPs). In the topsides facility, gas and oil are separated, treated and exported via dedicated subsea pipelines. The fluid compositions and properties across the various elements of the production system are used as input to the respective simulation models, and the corresponding outcomes (i.e. fluid properties, compositions, etc.) vary upon the well/caisson lineup and daily operating conditions.

Given the wide spectrum of fluids produced through the Perdido spar, a special Equation of State (EOS) characterization of the fluids had to be developed. As a common EOS model was utilized to characterize the fluids, we will call this the Unified Fluid Model (UFM) throughout this manusctript. This approach enables accurate and efficient prediction of the properties of blended fluids and is suitable for use in an Integrated Production System Model (IPSM) that connects reservoirs, wells, subsea flowlines network and topside facilities models. Such modeling scheme enables effective integration among relevant engineering disciplines and can represent production and fluid data from field history with high confidence.

The IPSM uses a black oil fluid description for the well and subsea flowlines network models. Based on the initial composition and producing GOR of each well, the fluid composition is estimated via a simple delumping scheme. The resulting compositon is tracked through the subsea network to the topsides facilities model, where compositional flash calculations are performed. The IPSM model can forecast production rates together with fluid properties and actual oil and gas volumetric rates across the whole production system. The model can be used to optimize production under constrained conditions, such as limited gas compression capacity or plateau oil production.
Diagnosis of Multi-Stage Fracture Stimulation in Horizontal Wells by Downhole Temperature Measurements
Authors: Cui Jingyuan , Zhu D. , Jin Minquan
Published: October 2014

Downhole temperature data measured by production logging tools (PLT) or distributed fiber -optic temperature sensors (DTS) are used frequently today to diagnose multi-stage fracture treatments in horizontal or highly deviated wells. This temperature data measured at the wellbore during and post fracture brings important transient flow information that helps engineers to understand the process of fracturing, the performance of fractured wells and therefore to optimize fracture design.

The interpretation models developed to translate temperature data to flow conditions can be fully numerical -based simulations or analytical/semi-analytical approaches. With reasonable assumptions analytical/semi-analytical models are more suitable for real-time field applications. This paper presents the applications of using a coupled semi-analytical fracture model and a wellbore model to predict temperature and pressure behavior in multiple-fractured horizontal wells during production. The thermal model calculated the heat transfer in the fracture/reservoir/wellbore system considering subtle temperature changes caused by the Joule-Thompson cooling effects. The results showed that transient temperature behavior is sensitive to estimate the fracture initiation points, number of created fractures and fracture geometry.

We discuss the characteristics of transient temperature behaviors corresponding to fracture geometry and flow rate distribution along a fractured horizontal wellbore. The temperature signal is typically strong at the toe and weak towards heel if the fractures are more evenly created along the wellbore due to the fluid mixture inside wellbore. Two field cases are presen ted to illustrate the application of using the temperature model to understand the fracture/flow distribution. The estimation of flow rate distribution from the temperature model is compared to the interpretation of flow by production logging tools. Although this is a single phase gas model, we can identify the water entries at certain location by matching the observed temperature with the calculated temperature. Flow distribution from the temperature model presents consistent trend with PLT measurement. Fracture diagnosis is more sensitive to the fluid entries (fracture locations) and less sensitive to the influence of multiphase flow inside the wellbore when compared with PLT tools.
Exploring Structural Uncertainty using a Flow Proxy in the Depositional Domain
Authors: Aydin Orhun , Caers Jef
Published: October 2014

Among various sources of uncertainty in reservoir modeling, structural uncertainty is often underrepresented. Evaluating different faulting scenarios requires gridding each of these scenarios. Preserving the structural geological realism requires careful consideration of structural hierarchy and abutting relationships. Enforcing such relationships often requires manual editing results. In this paper, a proxy method to efficiently represent uncertainty in structural modeling by building fault scenarios in the depositional grid is proposed, which is often a simple Cartesian grid. In this way accuracy (building actual complex fault models) is traded off with the ability to study uncertainty. A bottleneck in properly modeling structural uncertainty is caused by representation of faults as explicit surfaces. This is resolved in this paper with a proxy method by representing a faulting scenario as a fault block map which represents the compartments created in a reservoir by faults as a property on a Cartesian grid. These compartments defined on a Cartesian grid are easier to manipulate, allowing for fast generation of geologically consistent fault network realizations. Faults bounding these compartments are represented as transmissibility multipliers on the Cartesian grid taking into account their throw. Another bottleneck associated with structural uncertainty evaluation comes at the stage of simulating flow through a faulted reservoir. Running simulations in the physical domain where the grid is deformed with respect to fault throws may be cumbersome due to grid cell geometries around faults. Utilizing state-of the-art flow diagnostics on the Cartesian domain instead of a relatively slow finite element reservoir simulator on the physical domain allows the rapid evaluation and selection of fault networks for uncertainty quantification of forecasts.

To showcase the main functionalities of the proxy method, a small field example is used with small number of faults, where the full (and time-consuming) exploration of uncertainty is compared with uncertainty derived from the proxy method.
Mini-DST to Characterize Formation Deliverability and Heterogeneity in Thin Hydrocarbon Reservoir Sequences
Authors: Chu Wei-Chun , Steckhan Jan
Published: October 2014

A robust workflow is established to identify low-resistivity pay in thinly laminated sands with silty and/or shaly layers. The workflow integrates data from gas-while-drilling, conventional logging and nuclear magnetic resonance (NMR) logging for picking intervals for further examination using a wireline formation tester (WFT). A mini-DST is performed by means of a WFT equipped with either a single probe or a dual packer to determine the fluid type and productivity of each individual level.

Two field examples are presented to compare well performance predicted by the micro-scale mini-DSTs with macro-scale production tests. In both cases, the traditional DST is eliminated from the drilling/completion program. The final verification consists of comparing individual level contributions derived from the mini-DSTs with production logs.

In the first case, mini-DSTs are able to provide the fluid type and individual level transmissibility (kh/μ) for 8 out of 13 distinct levels. A cost-effective approach of running mini-DSTs by means of a WFT equipped with a single probe is demonstrated to investigate multiple levels in the thin hydrocarbon reservoir sequence. Guidelines are provided when a WFT with a dual packer is deployed to perform a mini-DST in the laminated formation.

In the second case, the same workflow was applied to derive the fluid type and transmissibility for two wells consisting of more than 30 distinct levels in the same field. After integrating mini-DST results from the two wells located 750 m apart, a framework is constructed to establish both vertical and lateral heterogeneities of thinly laminated reservoirs. The integration helps visualize a multiple-layered reservoir.

Our examples confirm mini-DSTs effectively define individual layer producibilities in multiple-layered reservoirs. The benefits are illustrated through case histories that demonstrate our ability to manage expectations of well performance in thin hydrocarbon reservoir sequences.
Enhancement and Potential of New Fluid ID Sensor Technologies for Sampling Tools
Authors: Cartellieri A. , Pragt J.
Published: October 2014

With the introduction of LWD fluid analysis and sampling tools new sensor technologies were adopted. Common are improvements of already existing technologies like the sound speed measurement or the density and viscosity measurement with a vibrating resonator. But also complete new sensor developments were introduced. The capability and accuracy of these sensors will be discussed in this paper.

Techniques used to obtain reservoir information include obtaining fluid samples produced from the subterranean formations. Modern fluid sampling tools incorporate various downhole tests and fluid identification methods. Often these technologies are used to determine the fluid contamination level for retrieving representative fluid samples for surface laboratory testing. It is desirable to evaluate fluids in the downhole environment to estimate various physical and chemical properties of the fluids. Downhole evaluations where the fluid under investigation remains substantially at in situ conditions increase the efficiency of the operation by reducing or eliminating the need to capture fluid samples, which requires retrieval of the evaluation tool from the borehole and provide better estimates by maintaining the fluid at substantially downhole conditions.

To achieve this objective, the new fluid analysis and sampling service incorporates a highly sophisticated pump and pump control system. With data derived from the exact pump displacement, a precise quartz pressure gauge and additional strain gauges the tool measures the compressibility of the fluid and delivers accurate cleanup mobility while pumping. The bubble point determination can be performed on demand and enables additional and highly precise information about the pressure-temperature-volume (PVT) characteristics of the reservoir fluid.

The improved optical refractive index measurement not only determines the fluid contamination in an oil or water environment, but also provides information about the fluid type and detects phase separation during cleanup. In addition to these measurements the density of the fluid can also be derived from the sensor. Evaluation of the thermal properties is performed via detection of the temperature difference between two sensors. The fluid downhole will be heated at a selected location followed by taking a plurality of temperature measurements and determining the thermal property of the fluid from the readings.

The recent enhancements and the potential of the new sensor technologies will be discussed based on results from different field tests worldwide. The calculation of the fluid density adapted from the downhole refractometer will be compared with results from laboratory measurements as well as measurements with other sensor technologies.
Diagenetic Influence of Aqueous CO2 on Fracture Conductivity of Shaly Rocks
Authors: Olabode Abiola , Radonjic Mileva
Published: October 2014

Most sedimentary rock formations (tight or highly porous) have geochemical characteristics that can lead to significant reactive ion exchange processes in aqueous media in the presence of carbondioxide. While geomechanical properties such as rock stiffness, Poisson's ratio and fracture geometry largely govern fluid flow characteristics in deep fractured formations, the effect of mineralization can lead to flow impedance in the presence of favorable geochemical and thermodynamic conditions. Shale caprock which seals more than 60% of oil and gas reservoirs have natural fractures that are unevenly distributed in the geosystem. Experimental works which employed the use of analytical techniques such ICP-OES, XRD, and SEM/EDS techniques in investigating diagenetic and micro-structural property of crushed shale caprock/CO2-brine system concluded that net precipitation reaction processes can affect the distribution of petrophysical nanopores in the seal rock. The results showed that geochemical precipitates can be formed such that fluid flow through open micro and macro fractures may be constrained. Simulation results reported by various researchers suggested that influx-induced mineral dissolution/precipitation reactions within shale caprocks can continuously close micro-fracture networks, while pressure and effective-stress transformation first rapidly expand then progressively constrict them. This experimental research investigates the impact of in-situ geochemical precipitation on conductivity of open micro-fractures under geomechanical stress conditions. Fracture conductivity in core samples of shale caprock with known mineralogical composition from different formations where CO2 injection is on-going are quantitatively evaluated under axial and radial stress using pressure pulse-decay liquid permeametry/core flooding systems. Modeling of the diffusion controlled fluid flow and induced fracture diagenetic alterations in the shale caprocks can be performed using CMG-GEM with artificial core imposing axial and radial geomechanical stress. The possibility of rock-fluid geochemical interactions constricting natural fracture conductivity in long term subsurface CO2 sequestration can lead to significant improvement in shale caprock seal integrity and mitigate injection induced geomechanical perturbation.
Characterization and Selection of Novel Magnetic Tracers for Dynamic Heterogeneity Identification and Quantification
Authors: Ali Khaled , Sohrabi Mehran , Ali Arfan
Published: October 2014

The substantial cost associated with the implementation of any enhanced oil recovery (EOR) program requires a robust understanding of the dynamic heterogeneity of the reservoir. The traditional methods used to determine the preferential flow paths are well-to-well transient pressure tests and tracer tests. This paper provides the results of a series of experiments with new types of magnetic tracers for the prediction of permeability heterogeneities and preferential flow paths in reservoir rock samples. Concentration prfile curves obtained for a number of new magnetic tracers are presented including water-based Ferro Fluids and water-soluble iron oxide powders. The magnetic properties of individual magnetic tracers are also presented which aid in the selection process of the optimum magnetic tracer.

To confirm the validity of the results obtained from magnetic traces, we compare the results against conventional tracer methods on the same core plugs. The results show a very good agreement between the two methods. One of the advantages of the magnetic tracers is the reduced analysis time of the core and effluent samples. The magnetic tracers can also be used in situations where there are constraints with using conventional tracers, for example, due to various chemical reactions in the injection lines, and/or with reservoir minerals deeper in the ground. The results of the new magnetic tracers can help in better understanding of the reservoir heterogeneity and sweep efficiency when combined with existing methods such as pressure transient analysis.
The HPHT Completion Landscape - Yesterday, Today, and Tomorrow
Authors: Lehr Douglas J. , Collins Scott D.
Published: October 2014

High pressure / high temperature (HPHT) wells demand the highest performance equipment and services for the safe and successful completion of these high risk and high cost projects. The demands associated with logging, shoe track isolation, equipment longevity and service life, completion and intervention options, and regulatory compliance push the limits of materials and services. The successful completion of HPHT wells requires advanced materials evaluations, collaboration among many disciplines, and sufficient time for product development and assessment to meet current industry and regulatory standards.

The tools utilized in HPHT completions are usually developed to meet the demands of a well or a family of wells. These tools include, but are not limited to, wellbore isolation plugs, production packers, liner hangers, perforating guns, Casing Collar Locators (CCL tools), formation evaluation tools, seal assemblies, and sub-surface safety valves. The methods used for HPHT tool development are evolving, and the development cycles are lengthening, particularly for ultra HPHT applications in which materials screening and stability assessments are required.

The development of tools for several recent Gulf of Mexico ultra HPHT wells required a multi-year schedule for development to industry and regulatory requirements. Due due to their extreme depths, ultra HPHT wells typically utilize architecture emphasizing small production casings across production intervals. This complicates cementing procedures, and severely limits product options. From an intervention standpoint, workstring options also become limited. Achieving mechanical success in these applications requires the operator to not only manage traditional resources such as time, people, and cash, but also the development of new high performance technologies in an evolving regulatory environment.

What can the industry anticipate for future HPHT wells in terms of architecture, product development, and regulatory challenges? This paper will review the industry's history in these areas, identify current development paradigms and regulatory challenges, and discuss the future challenges in well planning, product development, and regulation.
Visualization of CO2 EOR by Diffusion in Fractured Chalk
Authors: Eide Øyvind , Fernø Martin A. , Graue Arne
Published: October 2014

This work demonstrates that diffusion may be a viable oil recovery mechanism in fractured reservoirs during injection of CO2 for EOR. The oil production rate from diffusion alone, however, depends heavily on the distribution of CO2 within the fracture network and fracture spacing. High oil recovery was observed during miscible, supercritical CO2 injection (RF=95% OOIP after 5 days) in the laboratory using an artificially fractured chalk core plug. The development in 3D fluid saturations from CT-imaging made it possible to study the oil displacement in the vicinity of the fracture, and to calculate an effective diffusion coefficient using analytical methods. A numerical sensitivity analysis, using a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO2 injection declined exponentially with increasing diffusion lengths from the CO2-filled fracture and oil-filled matrix.
Granite Wash Optimization - Validating Completion and Production Techniques
Authors: Crawford E. M. , Energy Linn , Senters C. W. , Bullard K. E. , Leonard R. S. , Woodroof R. A.
Published: October 2014

The Granite Wash continues to be a prolific hydrocarbon producer, with over 1600 wells drilled during the last 10 years. During 2012 and 2013 an extensive development program was initiated by one operator in which 144 wells were drilled and completed with multi-stage hydraulically stimulated horizontal wells. Many of these wells utilized various types of completion diagnostics to: (1) evaluate vertical and horizontal communication within the Granite Wash, (2) identify potential horizontal loading problems and (3) diagnose long-term fracture fluid movement.

This paper reviews more than two years of water-based frac fluid tracer data. It details how the individual tracers were used to quantify communication between various layers of the Granite Wash and between nearby completed offset wells. Also, toe stage frac fluid recoveries were compared to identify wells that appeared to be constrained. Data will be presented documenting specific cases of inter-well and inter-zonal communication. This will include both offset wells that had been on production prior to the fracturing treatment and offset wells that had been recently drilled.

Extended sampling of individual fluid tracers can be an extremely useful tool in explaining production anomalies as they occur. On this project, the operator was able to identify the source of production changes and determine the best well intervention technique to economically increase production.
Measurement of Gas Diffusivity in Heavy Oils/Bitumens using Pressure-Decay Test
Authors: Ratnakar Ram R. , Dindoruk Birol
Published: October 2014

Molecular diffusion plays a very important role in various reservoir processes; especially in the oil recovery processes where convective forces are not dominant or when direct frontal contact and mixing is not possible. For example, in heavy oil and bitumen recovery, injected light hydrocarbons can diffuse into the oil beyond the potential fronts and/or convective zones and promote the effectiveness of the displacement process, and therefore, reduce in-situ viscosities which in turn enhance the oil recovery.

Similarly, diffusive mixing can also be a dominant mechanism in the gas re-dissolution process even in lighter hydrocarbon systems. For example, it controls how much gas will be dissolved in oil and how long it will take to dissolve, in the absence of mechanical/convective mixing, as in the case of reservoir re-pressurization. The extent of dissolution of a gas into oil is governed by its solubility but the rate is controlled by molecular diffusivity and solubility, both. Thus accurate determination of these parameters is essential to design and understand displacement processes.

Despite the significance of diffusion in various aspects of oil recovery, there are very few experimental studies available in the literature addressing the diffusion of gas in heavy oils. Experimental work is most commonly based on the Pressure-decay concept. However, the parameter inversion in these tests relies on an error function solution that neglects the transient processes at the gas-oil interface and assumes constant saturation concentration. This assumption is not appropriate because pressure in the gas cap changes continuously as gas is dissolved in the oil and hence the gas solubility varies with time. One of the major issues related to this experimental process is that it takes a long time (order of several days to few months) to achieve steady state (converged) solution to determine diffusivity.

In this work, we have

Experimentally investigated the diffusion of methane in heavy oils as well as light oils using pressure-decay test; Captured the transient effect at the gas-oil interface transient properly by expressing gas solubility in terms of Henry's constant in the model (1-dimensional diffusion equation coupled with pressure decline due to gas dissolution); Developed the exact solution of the model and shown that after long time, pressure decays exponentially in time with an exponent that depends on diffusivity as well as solubility; Presented the inversion technique, determined the diffusivity and other parameters from late transient pressure data, and showed the convergence in their estimates; and, Most importantly, we have developed a cut off criterion permitting us to stop the experiments while still being able to extract the converged diffusivity values (this is important in situations when the experiment is stopped prematurely for technical or other reasons).