bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Data Integration for Virtual Flow Metering
Authors: Moreno Gustavo A. , Garriz Abel E. , Badessich Matías Fernandez , Bottesi Germán L. 
Published: October 2014

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.