bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study of Alkaline/Polymer Flooding for Heavy Oil Recovery Using Channeled Sandpacks
Authors: Wu Yongge , Dong Mingzhe , Shirif Ezeddin 
Published: February 2011

Abstract
For heavy oils with viscosities ranging from 1,000 to 10,000 mPa·s (cP) in Western Canada, primary production and waterflood together can only recover 8 – 15 % original oil-in-place (OOIP) at their economic limit due to the adverse mobility ratio, severe water channeling and low reservoir pressure and formation voidage. These heavy oils usually have a relatively high content of acids which can react with alkalis to form in-situ surfactants. The loosely consolidated sandstone formations where these oils are deposited are characterized by high porosity, permeability and low reservoir temperature. These reservoir conditions are favorable for polymer application. Therefore, there is a potential to improve waterflood in these reservoirs by applying alkaline/polymer (A/P) flooding.
This paper presents the results of a laboratory study of A/P flooding for heavy oil recovery, including viscosity measurements, flood tests conducted in channeled sandpacks, residual resistance factor (Frr) determination, and residual oil distribution tests. A heavy oil with a viscosity of 1,202 cP and an acid number of 1.07 (mg KOH/g-oil) and produced brine collected from a heavy oil reservoir in Alberta are used in this study. The experimental results show that addition of polymer to alkaline solution reinforces stability and strength of in-situ formed emulsions. It is found that the distribution of the injected chemical solution into the high permeable cannels leads to the diversion of the subsequently injected chemical solution to low permeable zones with higher oil saturation due to the formation of blockage in the channel zones. Consequently, pressure build-up during chemical slug injection is the key to the improvement of displacement efficiency. Flood tests also show that alkaline-polymer flooding is more efficient than either alkaline flooding or polymer flooding. The optimal formulation for the heavy oil used in this study is 0.4% NaOH + 0.2% Na2CO3 + 1,000 mg/l polymer, with a tertiary oil recovery of 25 – 30 % OOIP over waterflood. Analysis of the results of the residual oil distributions in the channeled sandpacks at the end of A/P flooding shows that A/P flooding can effectively improve the sweep efficiency of waterflood for the heavy oil.
Application of the Ensemble Kalman Filter for Characterization and History Matching of Unconventional Oil Reservoirs
Authors: Chitralekha S. B. , Trivedi J. J. , Shah S. L. 
Published: February 2011

Abstract
Recently, the Ensemble Kalman Filter (EnKF) has emerged as an effective tool for performing continuous updating of petroleum reservoir simulation models. The method is firmly grounded on the theory of Kalman filters and sequential Monte Carlo techniques. The ability of the method to sequentially update the spatial properties in petroleum reservoir models, such as permeability and porosity, by integrating the dynamic production data makes it a very attractive approach. Moreover, the method takes into account the production uncertainty in the reservoir models by using error covariance matrices for the measurement vector (Production and injection rates, Gas-Oil ratio, Steam-Oil ratio, etc.) and the state vector (pressure, saturation, permeability, porosity). Similar to the traditional Kalman filter, the covariance matrices have to be tuned to reflect the uncertainty in the model and the measurements. We consider two unconventional oil reservoir models: 1) highly heterogeneous black-oil reservoir model, and 2) heterogeneous SAGD reservoir model. The results will demonstrate the advantage of using the localized EnKF for effective history matching using ensemble sizes relatively lower than what otherwise would be required with the ordinary EnKF. The results will also show the advantages of using prior knowledge available from the wells (permeability and porosity measurements) to generate initial realizations. One of the main practical advantages of history matching using the EnKF over traditional optimization based approaches is its low computational effort. The computational cost is dominated by Monte Carlo simulation of the ensemble of models only. Thus, significant computational time saving is possible by running each of the ensemble simulations on independent processors in a parallel mode. Moreover, the method can be easily integrated with any commercial reservoir simulation software.
Flow Regime Analysis of Multi-Stage Hydraulically-Fractured Horizontal Wells with Reciprocal Rate Derivative Function: Bakken Case Study
Authors: Luo Shanqiang , Neal Lane , Arulampalam Pathman , Jessica McDonough Ciosek 
Published: February 2011

Abstract
Activities in developing tight oil and gas reservoirs, such as the Barnett shale and the Bakken formation, have grown tremendously in recent years. Economic production of these unconventional resources relies heavily on advanced completion technology such as horizontal wells with multi-stage hydraulic fracture stimulations.
Unlike single-stage fractured vertical wells, multi-stage fractured horizontal wells (MFHW) exhibit a unique flow regime, compound formation linear (CFL) flow, which consists of linear flow in the formation toward the collective hydraulic fractures after interference has occurred between neighboring fractures. This flow regime can easily be mistaken for a reservoir-boundary (or compartmentalization) effect in production analysis. Such a misinterpretation will result in incorrect reservoir property estimates and long-term production forecasts.
This paper applies log-log reciprocal rate derivative plots to identify and analyze flow regimes of MFHW wells producing under constant bottomhole pressure. It is observed that the CFL straight line slope in the reciprocal rate derivative plot depends on the ratio of fracture length over fracture spacing but is not sensitive to reservoir permeability. As a result, the CFL slope can be used to diagnose fracture stimulation effectiveness.
Experimental Investigations of Hydraulic Fracture Growth Complexity in Slickwater Fracturing Treatments
Authors: Wang Y. , Miskimins J. L. 
Published: February 2011

Abstract
Friction-reduced water, i.e. “slickwater”, fracturing was first introduced in the late 1950&apos;s. It fell out of favor with the advent of gelled fluids systems; however, slickwater fracturing has seen a large resurgence with the increasing development of unconventional reservoirs. Slickwater fracturing has once again become popular for stimulating these tight gas sand and shale gas systems.
The main advantages of slickwater fracturing treatments are the economics and the adequate conductivity they can place in low permeability reservoirs. Additionally, it is possible for slickwater treatments to create long, complex fractures which enhance the well&apos;s “stimulated reservoir volume” (Mayerhofer et al. 2008). Most treatments use large quantities of water pumped at very high rates. However, the relationship between complexity and rate is not well understood.
This paper presents an experimental study on slickwater fracturing performed by using a unique testing system, which was developed to study slickwater fracturing treatments at a laboratory scale. The intent was to study the effects of rate on the complexity of growth in the reservoir. Laboratory results were scaled to field conditions by applying scaling law analysis. The scaled results suggest that for field water fracturing treatment design in shale reservoirs, large injection volumes result in large SRA (“stimulated reservoir area”, a comparison term to “stimulated reservoir volume”) which should result in increased production. The optimal injection rate can vary for different reservoir conditions. At low injection rates, reservoir complexity does not seem to affect fracture network growth. At the same time, different rock types will also affect the fracture network growth in water fracturing processes. Quantitatively, the laboratory results agree well with the conclusions drawn from actual field applications.
Lessons Learned and Experiences Gained in Developing Waterflooding Concept of Granite Basement Fractured Reservoir: 20 Historical Years Case Study
Authors: Dang Cuong T. , Nguyen Ngoc T. , Bae Wisup , Chen Zhangxing , Phung Thuoc H. 
Published: February 2011

Abstract
NFR represent over 20% of the world's oil and gas reserves. However, characterization of fractured reservoirs is complex and presents unique challenges in comparison with conventional reservoirs. It is immensely difficult to achieve the best results in secondary recovery process.
This paper presented the successful developments of waterflooding to overcome the complex geological characterizations of White Tiger field - the biggest fractured basement reservoir up to now on the continental shelf of Viet Nam. This reservoir has a complicated geological structure, very high heterogeneity, high temperature and closure stress. The total OIIP of this field reached nearly 4 billion barrels with 2000 meters of the oil bearing thickness and has been produced by more than 100 wells, tens of which flow at the rate of approximately one thousand barrels per day.
The geological study and fractured model were carefully investigated in both micro and macro scales to improve waterflooding performance. The authors analyzed the advantages and disadvantages of injection systems in basement reservoir during 20 historical years. And then, the artificial water buffer solution was proposed to develop waterflooding process. The authors described the establishment and the association of local artificial water buffer in basement reservoir. An effective method to adjust the injected water mass was also discussed. The excellent results in White Tiger field proved that average reservoir pressure and total oil recovery were significantly increased in comparison with previous injected schemes.
This paper is the precious guideline to solve some typical problems of waterflooding in fractured basement reservoir such as:
What could be applied waterflooding in basement fractured reservoir? What is the optimum injected rate and injected mass for basement fractured reservoir? How to evaluate the probability of high water cut in production wells during waterflooding process? How to predict the rising of artificial water-oil contact?
Shale Gas Reservoir Characterization Using LWD in Real Time
Authors: Han S. Y. , Kok J. C. , Tollefsen E. M. , Baihly J. D. , Malpani R. , Alford J. 
Published: February 2011

Abstract
A common practice in shale plays is to evaluate vertical boreholes with an extensive wireline logging program. Largely driven by cost, time and difficulty associated with acquiring wireline measurements in horizontal intervals, only data logged from the vertical hole is interpreted and used to define the reservoir profile for the horizontal target window. The horizontal wells are then steered based on simple gamma ray measurements by means of correlation against the vertical pilot wells. Detailed studies from a range of shale plays have revealed that the geosteering results for these wells using only gamma ray, are often questionable as it can provide non-unique structural modeling solutions.
Integrating Logging While Drilling (LWD) tools into the Bottom Hole Assembly (BHA) enables formation evaluation measurements to facilitate accurate well placement and perform detailed reservoir characterization across the target structure. Additionally, LWD measurements have been successfully used to avoid drilling hazards, enhance rate of penetration to reduce drilling time, and optimize completion designs. Using limited data for horizontal well correlations often result in inaccurate structural interpretations. This inaccuracy complicates the understanding of production variations between wells. By employing LWD, the uncertainties can be narrowed to enhance trajectory placement and provide a better understanding of the reservoir-production relationship. This relationship allows target refinement within the productive reservoir interval followed by an optimized completion for an overall increase in reserve recovery. This paper details the use of LWD measurements for accurate well placement, formation evaluation, and completion optimization within a shale gas play using an integrated shale gas solution.
Numerical Simulation on CO2 Sequestration in Saline Formations With Natural or Hydraulic Fractures Using a Discrete Modeling Approach
Authors: Liu X. , Gong B. , Huo D. 
Published: February 2011

Abstract
To find suitable locations to permanently sequester CO2 is crucially important for carbon storage. Deep saline formations are thought to be good candidates for CO2 sequestration due to their large capacity potential. On the other hand, cases have shown that saline formations can be naturally fractured to some extent, from small individual fractures to large-scale fracture clusters. Based on research from various scientific studies, pilot CCS programs and commercial CCS projects, formations and/or cap rocks with fractures may have significant leakage problems.
Modeling of CO2 flow in fractured systems remains a challenge. In this work, Discrete Fracture Modeling (DFM) that represents fractures individually and explicitly is applied to simulate CO2 transport in a saline aquifer. This requires unstructured gridding of the saline formation using Delaunay triangulation and transmissibility evaluation between each pair of adjacent cells. Simulations have been done using a connection list based simulator. Several examples, including injection to a formation with or without fractures and with different hydraulic fracture length, have been simulated based on data from an actual CCS project.
Results have shown that the existence of mudstone layers could prevent injected CO2 from leaking outside the reservoir when no fractures are present. While vertical fractures intersecting with mudstone layers will cause significant leakage increase as the fractures forms extremely preferential pathways for CO2 transport. On the other hand, if fractures are far enough away from the CO2 plume, it could alleviate dramatic pressure buildup caused by CO2 injection in the formation and thus help expedite CO2 propagation.
This work presents a systematic way of modeling CO2 sequestration in saline formations with natural or hydraulic fractures. The main application is to help improve evaluation and planning of possible CO2 storage location selection to identify and quantify possible leakage risks through existing or induced fractures in the injection process.
Thermal Properties of Formations From Core Analysis: Evolution in Measurement Methods, Equipment, and Experimental Data in Relation to Thermal EOR
Authors: Popov Y. A. , Spasennykh M. Y. , Miklashevskiy D. E. , Parshin A. V. , Stenin V. P. , Chertenkov M. V. , Novikov S. V. , Tarelko N. F. 
Published: February 2011

Abstract
New methods and instruments developed for measurement of rock thermal properties (thermal conductivity, thermal diffusivity, volumetric heat capacity, and coefficient of linear thermal expansion) have provided a sharp increase in the quality of experimental data for reservoirs and surrounding formations. Optical scanning technology primarily provides numerous high-precision, nondestructive, noncontact measurements of thermal conductivity and diffusivity directly on full cores, core plugs, and nonconsolidated rock samples and enables determination of thermal property tensor components and the recording of thermal property variations along cores. The instrument for simultaneous determination of thermal conductivity, diffusivity at formation temperature (up to 250 degC), and three-component pressure (pore, confining axial, and lateral) enables measurements at formation conditions to study thermal property variations during the heating of reservoirs and oil production in thermal enhanced oil recovery (EOR). The instrument for measurements of the coefficient of linear thermal expansion at temperatures up to 250 degC within every temperature interval of 20 degC provides measurements on core plugs that account for rock anisotropy. Application of the new techniques to study more than 8,000 cores from 17 Russian oil-gas and heavy oil fields provided a representative thermal property database for sedimentary rocks saturated by brine, oil, and gas, accounting for rock anisotropy and inhomogeneity as well as formation pressure and temperature. New correlations between thermal and other physical properties were established. The new experimental data demonstrated that previous information on thermal reservoir properties often needs to be significantly corrected. The new instruments provided detailed information on the spatial and temporal variations in the thermal reservoir properties during thermal EOR. Authors used this to construct detailed 4D reservoir models for estimation of reservoir thermal regime, thermal losses, and heat and mass transfer within reservoirs, enabling better design and optimization of thermal methods of EOR.
Application of CT-Conveyed Perforating with the Sand Jetting Technology on North Sea Deep Horizontal Tight Gas Producer
Authors: Fryzowicz R.. , Naughton-Rumbo R.. , Schrama E.. 
Published: February 2011

Abstract
Tight gas developments in the high cost environment of the North Sea are becoming economical and operators are focusing on the technology required to realise these plays and extend field and facility life. Operating companies are targeting tight gas reservoirs with low to very low permeability with long deviated and horizontal wellbore sections. Close attention to the perforating method is required in order to optimise hydraulic fracturing operations whilst minimising rig time.
Sand jetting technology has been in use by various industries for many years. Although theoretical papers for oilfield applications were published as early as the 1960s (Brown et al, 1960), it was only after advances in steel metallurgy in the last decade that tools could be made robust enough for real-world oilfield use. In addition, simulation software has improved greatly in recent years, yielding better predictability for this type of operation.
This paper will describe coiled tubing-conveyed sand jetting perforating operations for a five stage multi-frac horizontal gas well in the Southern North Sea. The goal of the operation was to create perforations with minimal entrance friction, reduced tortuosity during treatment, and minimise the chance of multiple fractures. Such a treatment would reduce the chances of premature screen-out and the associated costly rig time as well as allow for optimised placement of the proppant following a tip screen out (TSO) design. The challenges associated with performing the operation on a small, unmanned satellite platform will be described, along with pre-job planning and operational steps taken to ensure the sand jet tool could reach the target depths in the deviated well.
Leveraging Slim Hole Logging Tools in the Economic Development of the Ghawar Fields
Authors: Ariwodo I. , AL-Belowi A. R. , BinNasser R. H. , Kuchinski R. S. , Zainaddin I. 
Published: February 2011

Abstract
Traditionally, brown field developments have often required the plug-back and side-track of existing drain-holes, to target any nearby opportunities. With advances in drilling technology, there is a general preference to drill small diameter wells due to the comparative cost advantage of small holes.
In the recent times, this preference has led some wireline service companies to start to offer open-hole formation evaluation services with slim tools having diameter in the 2.0 -to- 2.5 in range. At present, most of the traditional petrophysical measurements can be acquired utilizing slim tools. In addition, several "specialized" measurements such as cross dipole sonic, formation pressure testing, and resistivity imaging can also be acquired. The use of battery and memory technologies has allowed these tools to be deployed using a broader range of conveyance techniques allowing for reduced risk in the entry of slim wells.
The provision of slim hole logging services has created an opportunity in the industry to leverage these tools for the economic development brown fields. Thus short horizontal sidetracks and well re-entry’s to test deeper horizons can be drilled and logged successfully. Saudi Aramco has been able to leverage these tools in its continued development of the giant Ghawar field. Some of the development projects are listed below; Some horizontal side-tracks with 3–7/8" hole sizes have been drilled under high dog-legs than was previously impossible and logged successfully.It is now possible to run well-completions in newly drilled wells that have well control problem. A provision is made to subsequently log these wells with slim wireline logging tools.It is now possible to run a complete suite of wireline logs across some old wells that were previously completed without a full formation evaluation logging suite.Slim-hole formation resistivity imaging services are now being provided, to aid in the identification of borehole break-out and fractures features that might affect the well’s productivity.Slim hole formation pressure testing have been acquired in slim wells in order to generate a pressure gradient, determine oil mobility, and define oil-water contacts
Several case studies would be used in this paper to demonstrate how Saudi Aramco has leveraged these slim wireline tools to realize some development opportunities. Also examples would be used to show that these slim tools do not compromise the quality of log data acquisition.