bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Effective Accelerated Pulsing Injection Method for Restoring Injectivity in Waterflood Fields with Selective Injection Systems with Side-Pocket Mandrels and Control Flow Valves
Authors: Escobar-Remolina J. C. , Barrios-Ortiz W. , Mantilla-Villamizar J. , Vargas-Medina J. A. , Sanabria-Gomez L. , Davidson B. C. , Sanchez-Lona A. , Wegmann-Sanchez J. M. 
Published: June 2014

Abstract
This paper presents the performance of three water injection wells, INJ-1, INJ-2, and INJ-3, at the Ecopetrol's Yarigui Cantagallo field re-completed with newly designed pulsing selective control valves (P-SCFV). The three wells originally had conventional selective control flow valves (C-SCFV) in side-pocket mandrels. While a total of 31 valves were replaced in seven wells, this paper will focus on the three wells where 12 P-SCFVs were installed and the injection data gathered and interpreted.
Enhanced Oil Recovery (EOR) and/or chemical methods are routinely used to improve oil recovery when production levels decline due to reduced formation pressure, poor displacement efficiency, and adverse mobility ratio. For decades, oil production companies with waterflood recovery schemes have employed various types of well completions for water injection, including selective completions with side-pocket mandrels.
When an injection zone loses its capacity to admit water, the optimal sweeping capacity will not be reached, and then the operator will not achieve sufficient oil production to maintain profitability. In the Yarigui Cantagallo field 12 P-SCFVs were installed (4 in each injector well), with the objective of overcoming the loss of injectivity in each injection zone due to blockages and permeability decay on the formation face, primarily as the result of calcium carbonate deposition. The new P-SCFVs were run to demonstrate that they could overcome the common problem of permeability decay with the objective that injectivity performance could be increased and sustained over an extended timeframe.
The 12 P-SCFVs have been in operation for 12 months, and the comparative results have shown performance optimization that conventional C-SCFVs could not achieve, such as, intervals previously not accepting injection water gradually (after ∼ one month) accepting water from the P-SCFVs. The latter confirms the theoretical and practical efficiency created generated by a flow field that concurrently establishes a repeated pulsed water hammer effect and the creation of numerous vaporization zones, which result in the formation of cavitation bubbles. These vaporization cavities work in consort with the water hammer effect to clear detritus material from the mandrel and formation face giving rise to increased near wellbore permeability.
Lab Observation of Low Salinity Waterflooding for a Phosphoria Reservoir Rock
Authors: Jiang Haifeng , Chopping Curtis G. , Forsman Chad , Xie Xina 
Published: June 2014

Abstract
Improved oil recovery by low salinity waterflooding for carbonate rocks has been observed both in labs and in field pilot tests. The objective of this lab study was to test if low salinity waterflooding was an option for improved oil recovery for a Phosphoria reservoir in the Big Horn Basin, Wyoming. Reservoir rock and the crude oil along with production history and water chemistry data were provided for the lab study. Petrological study indicated that the reservoir rock consists of dolomite, anhydrite, and chert nodules and is naturally fractured. The average porosity and permeability of the cores were about 10% and 2 md, respectively. To ensure relative homogeneity, reservoir cores were selected by CT scanning to confirm that there were no visible fractures and large size chert/anhydrite nodules.
Spontaneous imbibition tests were performed with synthetic formation water followed by diluted water in tertiary mode at ambient pressure and reservoir temperature. Oil recovery from 5 to 30% OOIP was achieved by spontaneous imbibition with synthetic formation water. The reservoir rocks appeared to be intermediate to weakly water-wet and mixed-wet. The oil recovery did not increase after low salinity water was used for continuous imbibition. Coreflood tests were performed at reservoir pressure and temperature. Oil recovery ranged from 38 to 64% OOIP by secondary waterflooding with synthetic formation water, accompanied by high differential pressure across the core samples. The subsequent tertiary low salinity waterflooding did not result in additional oil recovery, while anhydrite dissolution was detected. This study shows that low salinity waterflooding may not an effective method for this reservoir.
Accurate Tight Gas Flow Simulation: Where the Real Gas Pseudo-pressure Must Be Used
Authors: Lu Bo , Shiralkar Gautam 
Published: June 2014

Abstract
Because of the growing importance of unconventional gas (shale gas, coalbed methane, etc.), gas flow simulation has been receiving greater interest in the industry. Although the real gas pseudo-pressure m(p) approach has been available for some time, many commercial simulation tools still use gas pressure as the basis for gas flow calculations. There is a widely held perception that, while the m(p) approach can result in faster simulation runs, the two approaches are essentially equivalent or interchangeable. Herein, we show that well productivity is often significantly over-estimated when the standard pressure based approach is used for tight gas reservoirs. The effect is more pronounced at lower pressures.
We demonstrate that the difference in results arises from the numerical dispersion in the simulator associated with the pressure formulation. We discuss the implementation within a simulator that models both sub-surface flow as well as flow in a surface network. This allows comparison of simulation runs using the two different formulations.
Finally, we present several examples simulating gas flow in tight reservoirs with wells that are horizontally and vertically fractured, as well as a multi-well example. The m(p) approach is shown to yield accurate results in contrast to the pressure approach. This has important implications for simulations on a field wide scale and when other phases are present along with gas.
This paper shows that the real gas pseudo-pressure approach should be used to simulate tight gas reservoirs, through which the well productivity can be accurately estimated. The implementation approach is also applicable to other commercial simulators in the industry.
Increased Oil Recovery by Permeability Modification in High Permeability Contrast Slim Tubes
Authors: Jackson Scott , Fisher John , Fallon Robert , Norvell Joseph , Hendrickson Edwin , Luckring Abigail , D'achille Ben 
Published: June 2014

Abstract
Biofilm and biopolymers produced from microbes have been shown to reduce the permeability of high perm streaks which can result in improved sweep efficiency. The rate of permeability modification is very reproducible but can vary depending on the specific treatments used. Our approach has been to inoculate the reservoir with a microbe that under the optimal nutrient conditions will express a biopolymer as a film, reduce the size of pore throats and reduce the apparent permeability. The microbe and the nutrients are tailored to the conditions of each reservoir thus giving MEOR the greatest chance for success. In this paper we describe the use of a high permeability contrast composite slim tube to demonstrate increased oil recovery using microbes that generate biofilms to reduce the permeability contrast and thus improve sweep efficiency. In this setup, three hydraulically constrained slim tubes – working as very long sand packs – were constructed from different sources of sand with a range of particle size distributions. Absolute and differential pressure transducers were used to monitor the pressure drop across individual slim tubes and across the composite configuration of the three slim tubes. Oil traps were located at the exit of each slim tube to measure the oil production from each tube. The permeabilities of the slim tubes against a high salt injection brine (TDS ∼ 85,000 ppm) were measured to be 45, 4.5 and 2.6 Darcy. This presented a challenging system with a slim tube at a very high permeability that would need to be reduced by the MEOR treatment. Oil (viscosity of ∼58 cp) was pumped independently into each slim tube to assure that each slim tube was at residual water saturation. The slim tubes were allowed to age before the start of the test. Once working in composite mode the flows of the injected brine and MEOR treatments were dictated only by the hydraulics of the composite slim tube. The produced fluids from all three slim tubes were sent to a single back pressure regulator. In the composite mode, oil was readily produced only from the high permeability slim tube during the initial (non-MEOR) flooding sequence. A salt tolerant microbe present in the target oil reservoir capable of producing biofilms and altering the permeability was inoculated into the composite slim tube. The inoculated microbes were batch fed periodically using a protocol that was scaled down from one that would be used in a field test. An increase in the pressure drop and corresponding increase in oil production from the lower permeable slim tubes was observed as a result of the treatment. This resulted in a dramatic increase in the recovery factor from the composite slim tube. This work is a continuation of tests described in earlier papers (SPE129657, SPE146483 and SPE159128 – references 4, 5 and 6).
The Role of Counter-Current Flow in Simultaneous Water and Gas Injection Processes
Authors: Sherafati Marjan , Javaheri Mohammad , Jessen Kristian 
Published: June 2014

Abstract
In this work, we are investigating the effect of flow reversals from co-current to counter-current flow on the displacement performance of simultaneous water and gas (SWAG) injection processes. In simultaneous injection processes, gas migrates towards the top of the formation while water tends to move towards the bottom of the formation. The gravity segregation between gas, oil and water will result in counter-current flow occurring in the vertical direction in the reservoir. Experimental and theoretical studies have reported that relative permeability to each phase is less during counter-current flow as compared to co-current flow. The significance of this reduction depends on the gravity number. A reduction of relative permeability in the vertical direction results in anisotropy in relative permeability. This effect has to the best of our knowledge not previously been considered in the simulation of EOR processes.
To investigate the impact of flow reversals on displacement performance, we have implemented a new model that accounts for mobility reductions during counter-current flow in a three-phase compositional, IMPES simulator. A range of displacement settings, covering relevant gravity numbers and miscibility conditions (near-miscible and multicontact miscible), have been investigated to gauge the impact of mobility reductions due to flow reversals. The conventional mobility model (ignoring the impact of counter-current flow) is compared to the proposed mobility model and we demonstrate significant differences in the predicted displacement performance in terms of saturation distributions and recovery estimates. Accordingly, we recommend that an explicit representation of flow transitions between co-current and counter-current flow should be included to ensure accurate optimal design of SWAG processes.
Effective use of Information Technology in Spill Response - How an Integrated Web Portal can Facilitate the Response Effort
Authors: Kerr James , Braisted Robert , Sukkurwala Ghazanfar (Gus) , Teeling Michael 
Published: June 2014

Abstract
Spill responses are stressful and chaotic enough without the added burden of difficult or poorly categorized information. A Web Portal can provide an interactive geographic information system (GIS) map, access to data, and integration with a mobile data collection system to support spill response activities. Effective use of these tools can streamline the response effort and provide the responsible party, responders, regulators and the public access to current information. Incorporating the globally recognized Incident Command System (ICS) architecture into the Web Portal allows for easier coordination with local, state, and federal agencies. Linking GIS tools to the portal allows users to access spatial information and to query a variety of datasets in real-time. In short, a collective Knowledge Management System (KMS) extends beyond standard data management to provide a new way of addressing spill response.
Mobile devices can be used to collect field information that has historically been collected using manual techniques. The information can then be synchronized with a central database through the Internet or by direct download. The database can be linked through a Web Portal to interactive mapping tools providing near real-time information for decision-making and communication. Because significant spill responses in the United States and many other major industrialized countries around the globe use the ICS structure, it is also useful to have an electronic format that mimics that approach. This allows data to be collected, compiled, analyzed and disseminated in a consistent manner that the responders and regulators understand.
The need for timely and accurate information in our current sound bite society is critical. The use of data that is collected, compiled, analyzed and disseminated using electronic methods improves timeliness and accuracy. In addition, by consolidating information in the ICS structure, the data remain repeatable, defensible and reliable as the response effort moves from response phase, into project phase through to closure.
The continued increase in exploration, production, transportation and distribution of North American oil and gas from both conventional and unconventional sources increases the probability of more spills. The timeliness and accuracy by which industry responds to a spill will go a long way in determining the verdict in the court of public opinion and shaping the future laws that govern our business efforts.
Proppants Selection Based on Field Case Studies of Well Production Performance in the Bakken Shale Play
Authors: Hu Kyle , Sun Jianlei , Wong Joe , Hall Bobby E. 
Published: June 2014

Abstract
A brief overview of different proppant types and amounts used in stimulation designs in the Bakken shale play since 2011 is presented in this paper. The primary goal of the paper is to determine the long-term production and economical effectiveness on hydraulically fractured wells using different proppant types, percentages of proppant types and overall amount of proppant in the well completions. The results are based on four case studies that focus on 72 wells in four different fields in the Bakken formation of the Williston Basin.
In these four case studies, the primary variable that affects the difference in long-term production of the different well groups is the percentage and amount of each proppant type used in the completion design. Completion and stimulation data was collected from public resources such as the North Dakota Industrial Commission (NDIC) database. In each case study, wells in the same field were grouped. For each group of wells, the average long-term production and economical effectiveness was analyzed.
The case studies in the Capa Field in Williams County North Dakota and the Chimney Butte Field in Dunn County North Dakota shows that over a 270 day period, in each group of wells completed with about 30 percent ceramic proppant mixed with silica sand, the wells produced an average of over 100 percent more than the comparable group of wells completed using only silica sand. The case study in the East Fork Field in Williams County North Dakota shows that after 270 days of production, the group of wells using 100 percent ceramic proppant attained an average of 27 percent production increase over the group of wells using an average of 62 percent ceramic proppant. These wells also attained a 67 percent production increase over the group of wells using an average of 35 percent ceramic proppant.
In comparing completion procedures in these high-producing fields, using a combination of high percentages and large amounts of ceramic proppant has yield higher production and EUR. The use of ceramic proppant not only covers the additional proppant cost in a short period of time, but also generates higher revenue in the long term. The findings from these case studies should apply to all fields that have similar reservoir characteristics.
High Performance Ceramics in the Bakken
Authors: Crafton J. W. , Herndon D. , Kaul T. 
Published: June 2014

Abstract
An investigation of the performance of a group of 38 Bakken, Montana and North Dakota, horizontal wells was conducted for the purpose of assessing the relative benefit of premium ceramic proppants compared to 20/40 white sand and other ceramic proppants. The observed production histories of the wells, normalized for reservoir quality, severity of pressure drawdown and treatment type and size, were used as the basis for the comparison. The primary performance metrics employed were: apparent or effective fracture half-length normalized for the amount of placed proppant, sustainability of the reservoir/wellbore connectivity, impact of artificial lift installation, incremental oil equivalent recovery at various points in the production histories and impact of rate of pressure drawdown. The premium proppants had similar benefit, while the third ceramic proppant actually performed more poorly than the 20/40 white sand.
Sensitivity to the various damage mechanisms, such as rapid reduction in surface flowing pressure, the impact of shut-ins and delay to artificial lift installation are discussed in the paper. Based on equivalent oil recovery, there is clear evidence of a completions related point of diminishing returns. All of these observations call into question the "minimum cost" well management strategy. Benefits are derived not only from significantly better hydrocarbon recovery and longer apparent fracture length, but less damage during shut-ins and artificial lift installation, along with less sensitivity to pressure drawdown.
Analysis of Decline Curves Based on Beta Derivative
Authors: Shahamat M. S. , Mattar L. , Aguilera R. 
Published: June 2014

Abstract
This paper presents a new simplified method for forecasting oil and gas production during transient and boundary dominated flow (BDF), which does not require the use of complex analytical or numerical modeling tools. The method is based on the behaviour of the beta derivative (β), where two approximate straight lines are obtained during transient flow and BDF with slopes mt and mb, respectively.
The method is applicable not only to vertical wells in conventional reservoirs producing during BDF but also to hydraulically fractured vertical/multifractured horizontal wells in unconventional reservoirs with prevailing transient (linear) flow. Upon selection of an appropriate βBDF (which mainly depends upon the type of flow regime, i.e., radial or linear) and using the proposed equations, type curves can be generated that provide a convenient method for obtaining the slopes of beta derivatives for transient flow (mt) and BDF (mb) through a type curve matching process. The method is validated by comparing results against oil and gas numerical simulations of vertical and hydraulically fracture vertical wells.
The developed method is not biased toward any flow regime or presence of skin. Flow regime and skin effects are embedded in the βBDF and mt parameters. Transient and BDF flow are accounted for through the slopes mt and mb, respectively. Corroborated with the use of numerical simulation, the proposed method provides reliable production rate forecasting while staying away from the complexities of analytical or numerical modeling.
Multi-stage Hydraulic Fracturing Design In Horizontal Wells With The Use Of Drill Cuttings
Authors: Olusola Bukola K. , Aguilera Roberto 
Published: June 2014

Abstract
Successful multi-stage hydraulic fracturing of horizontal wells requires a clear understanding of the in-situ stress profile. This implies knowledge of rock properties and pore pressure variations throughout the wellbore. These properties can be determined with a good level of certainty when complete data sets are available.
In practice, however, data scarcity from horizontal wells is the rule rather than the exception. This has led in most instances to performing multi-stage hydraulic fracturing jobs in symmetric intervals throughout the horizontal well without regard to the optimum locations where hydraulic fractures should be initiated.
This study shows how data extracted from drill cuttings collected in a horizontal well can be used for optimizing multi-stage hydraulic fracturing. The cuttings are used in the laboratory for measuring porosity and permeability and for estimating geomechanical properties (e.g. Young Modulus, Poisson's ratio, brittleness index). The data permit generating the in-situ stress profile and other geomechanical parameters in a hydraulic fracturing model.
A comparison is made of two cases in a horizontal well of the Western Canada Sedimentary Basin (WCSB), where only a gamma ray log is available: In one case drill cuttings are used for estimating geomechanical properties to select fracture initiation zones; in the other case symmetric fracturing stages are selected without giving consideration to geomechanical properties.
The conclusion is reached that the petrophysical and geomechanical knowledge acquired from the study of drill cuttings leads to better rates and improved ultimate recoveries.