bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Tracers To Evaluate and Optimize Scale-Squeeze-Treatment Design in the Norne Field
Authors: Vazquez O.. , Mackay E.. , Tjomsland T.. , Nygård O.. , Storås E.. 
Published: March 2015

Summary
When squeezing scale inhibitors (SIs) into oil-production wells, the inhibitor should usually be uniformly placed in the open intervals to optimize squeeze lifetime. In wells with varying reservoir quality and/or significant crossflow, however, uniform placement is difficult to obtain. Flow diverters are frequently used to improve the chemical placement. In many cases, it is of great interest to evaluate the squeeze performance and assess the actual placement and back production of inhibitor to gather well information and thereby optimize future squeeze designs. This can be particularly interesting in subsea wells in which other types of data collection, such as production logging, are not feasible because of high intervention costs and high operational risk. This study suggests the use of tracers during squeeze treatments to evaluate the placement as an alternative to running production-logging tools (PLTs).
The main purpose of this paper is to demonstrate the applicability of tracers [in this particular study, the injection of a potassium chloride (KCl) slug in a producer well in the Norne field] to evaluate the layer flow-rate profile along the completion interval, which depends on the pressure and geological properties of each layer. The study consists of verifying the layer flow-rate profile predicted by a history-matched reservoir model. On the basis of this layer flow-rate profile, a tracer-injection program is designed, which includes two production stages at different rates. Finally, on the basis of the reservoir-model predictions, it is identified that each layer is at different pressures, which leads to a distinctive return profile.
To evaluate the match between the observed data and the simulation data, the layer flow-rate profile from the reservoir model was used to populate a specialized near-wellbore model for scale-squeeze treatments. The match between the observed data and the simulated data was good. However, the near-wellbore model, in particular the layer flow-rate profile, was fine-tuned further. Finally, the fine-tuned near-wellbore model was used to optimize future treatments more accurately with the fine-tuned layer flow-rate profile.
Activator Development for Controlling Degradation Rates of Polymeric Diverting Agents
Authors: Reddy B.R.. R. , Cortez-Montalvo Janette 
Published: March 2015

Summary
Hydrolytically degradable polymers (generally aliphatic polyesters) have been used in a variety of applications in the oil field, such as fluid diversion, fluid-loss control, and filter-cake-removal applications. In general, diverting agents and fluid-loss-control materials are only necessary to perform the intended function for a finite amount of time. Once the well is completed or placed on production, it is desirable that the degradable materials be removed so that they no longer have any influence on subsequent fluid flow. With time and temperature, the degradable polymers will break down by forming water-soluble byproducts, leaving behind limited, if any, residual formation damage. The effective formation sealing by these materials while in place, and eventual cleanup, has made them sought after materials for a growing number of applications. However, for cooler temperatures and applications for which the well must be placed on production rather quickly, there have not been many options to controllably increase the rates of polymer degradation.
Strong acids and bases are known to accelerate the degradation of polyesters. Use of these materials can present several disadvantages, such as corrosion and/or undesirable reactions with the formation. This paper discusses amine- and aminoalcohol-based compounds as potential degradation accelerators (DAs) of polymers containing ester-functional groups in the polymer backbone. Oligomeric polyamines, such as ethylenediamine (EDA) and its homologues, and aminoalcohols, such as ethanolamine (EA), were tested as accelerators for polymer breakdown. Commercial polyesters tested in this study had variable crystalline and amorphous content. With one exception, polyglycolic acid (PGA), all polyesters contained polylactic acid (PLA)/polylactide either exclusively or as one of the components. The tests were performed under static conditions by aging known quantities of particulate polymers with identical particle-size distributions in excess aqueous fluids, and loss in recovered dried mass was measured periodically at test temperature. The results indicated that oligomeric polyamines accelerated polymer degradation significantly compared with water. The degradation rates were the highest for totally amorphous polymer and decreased with the increase in crystallinity. Some semicrystalline polymers appeared to increase in weight initially before manifesting weight loss because of degradation, especially in the presence of a polymeric amine, and to a lesser extent in the presence of water. Among aminoalcohols, EA containing a primary amine group was significantly more effective than that containing a tertiary amine in degrading semicrystalline polymers. Trialkanolamines appeared to cause swelling of the particulate semicrystalline polymers before significant weight loss from degradation manifested. Mechanistic implications of the results relating the degrading chemicals and the polymer properties and compositions are proposed.
Evaluation and Performance of Packer-Type Downhole Gas Separators
Authors: McCoy J.N.. N. , Podio A.L.. L. , Rowlan O.L.. L. , Becker D.. 
Published: March 2015

Summary
Advances in horizontal drilling and large fracturing technology have resulted in wells that produce larger volumes of oil and gas than have been common domestically. Artificially lifting large volumes of oil and associated gas to the surface has always been a problem because of the difficulty of separating liquid from large volumes of gas downhole, especially in rod-pumped wells.
This paper describes a separation technique that uses a packing element to divert the formation fluids through the separator and into the casing annulus at the top of the separator, above the pump inlet at the bottom of the separator, so that the liquids and gas can separate by gravity. The pump seating nipple is located at the bottom of the separator so that the pressure drop is less in the liquids moving from the casing annulus to the pump intake. Better pump fillage is obtained with the technique of setting the pump intake at the bottom of the separator rather than above the long separator, as show by the field data.
This paper also describes a quantitative technique for evaluating the effectiveness of downhole gas separators. Often, the evaluation of separator performance is based only on pump fillage and the total gas production from the well, instead of a comparison of the liquid fillage in the pump in relation to the percentage of liquid that exists in the casing annulus surrounding the pump.
Time-Dependent Fracture-Interference Effects in Pad Wells
Authors: Manchanda R.. , Sharma M.M.. M. , Holzhauser S.. 
Published: March 2015

Summary
Hydraulic fracturing in shale formations induces microseismic events in a region we refer to as the microseismic volume. Many of these microseismic events are signatures of failure in the formation that are believed to be a result of induced unpropped (IU) fractures beyond the primary propped fracture. Areally extensive microseismicity may be evidence that these IU fractures occur and extend spatially beyond the propped fracture during pumping in many unconventional reservoirs. We present evidence that these fractures close over time after pumping is stopped and that this closure of IU fractures can have a significant impact on stress interference between fractures.
To illustrate these effects, microseismic and radioactive-tracer data are presented for four laterals drilled and fractured from a single pad. Two wells on this pad were fractured with the consecutive-fracturing sequence, and the other two wells were fractured with the zipper-fracturing sequence. Geomechanical simulations were performed to model the pad scenario and explain the microseismic and tracer observations, with emphasis on the two different fracturing sequences.
Our simulations show that the opening of the IU fractures results in significant temporary changes to the stress field in the rock. One consequence of this is that later fracture stages tend to propagate into the open-fracture networks of IU fractures created earlier because of stress reorientation. This can lead to inefficient usage of fluid, proppant, and capital because the region that is being stimulated has already been stimulated by the previous stage. By analyzing the net pressure, radioactive-tracer data, and microseismic data from the four-well pad, we show that these IU fractures close over time because the fracture fluid leaks off. This reduces the stress shadow, and subsequent induced fractures are no longer subjected to the significantly altered stresses, allowing for more-efficient fracture-network coverage by subsequent fractures in a horizontal well. On the basis of the data presented and computer simulations, we propose the idea of maximizing the time between fracturing in the microseismic volume of a recently fractured region (within operational constraints). The time required for the IU fractures to close can be estimated from our models and varies on the basis of the reservoir and fluid properties from several hours to days. One example of how this is accomplished in practice is zipper fractures. However, our work suggests that there also may be other fracture-sequencing strategies for accomplishing this.
Geology and Geohistory Contribute to Flow Assurance, Part II: Asphaltene-Risk Evaluation Incorporating Geological Heterogeneity and Covering All Operating Temperatures
Authors: Yonebayashi Hideharu , Tosic Slavko 
Published: March 2015

SummaryThis paper will present more-detailed discussion of asphaltene risk by updating new asphaltene-onset-pressure (AOP) results, and it will capture range-of-temperature conditions (i.e., from reservoir temperature to surface-operating temperature). For integrating these updates into the risk-matrix chart proposed in the previous work by Yonebayashi et al. (2013), geological heterogeneity of fluid-sampling location will be taken into account. A study of numerical modeling (applying the cubic-plus-association equation of state) treated the geological heterogeneity as a variation of asphaltene content, and reproduced asphaltene-precipitation envelopes, which were well-matched to the overall trend of experimental AOP detection. To conclude, this work reduced the uncertainty of the asphaltene-precipitation boundary at reservoir temperature, and showed a consistent shifting of the asphaltene-precipitation boundary by temperature range.
Fines Migration in Fractured Wells: Integrating Modeling With Field and Laboratory Data
Authors: Marquez M.. , Williams W.. , Knobles M.. , Bedrikovetsky P.. , You Z.. 
Published: March 2015

Summary
Production and drawdown data from 10 subsea deepwater fractured wells have been modeled with an analytical model for unsteady-state flow with fines migration. The simulation results and the field data indicated a good match, within 5%. A sensitivity study conducted on initial concentration of fines, flow rate, maximum fines-mobilization velocity, fines distribution, formation damage, and filtration coefficients confirmed that the model-matching parameters are within values reported commonly in the literature. This paper describes the methodology used to integrate the modeling predictions with field and laboratory data to identify probable causes for increasing skins and declining productivity-index values observed in some of the wells under investigation. It discusses the results of an experiment designed to simultaneously assess the effects of pressure depletion and compaction on fines production and permeability with a triaxial-stress apparatus. This is, to the best of our knowledge, the first time an experiment of this nature is reported in the literature. The good match between the modeling and the field data, further validated with laboratory experiments, allows for discussion of long-term predictions on well productivity impacting current reservoir-management strategies and field-development plans.
Use of Model-Predictive Control for Automating SAGD Well-Pair Operations: A Simulation Study
Authors: Patel K.. , Aske E.M.. M. , Fredriksen M.. 
Published: March 2015

Summary
For more than a decade, the steam-assisted-gravity-drainage (SAGD) process has been in use commercially to extract heavy oil from Athabasca oil-sand deposits located a few hundred meters below the surface. Operating challenges in the SAGD phase of operations arise not only because the process is hidden below the surface, but also because of the number of well pairs needed to drain the reserves and the number of variables that need to be considered for each well pair.
Different control philosophies have been suggested and used to control SAGD well pairs, which focus on a single variable or a few out of the many variables to be considered. None of these philosophies have been found to consider the well pair as a whole, with interactions between the downhole variables, and none of the philosophies have been found to include predictive capability. In this paper, we demonstrate, for the first time, how model-predictive control (MPC) can be used to control, stabilize, and assist optimization of an SAGD well pair.
This paper shows how we used proprietary MPC software to control and stabilize a typical configuration of a numerically simulated virtual SAGD well pair. Our simulation results demonstrate that MPC is suitable for use in the SAGD industry and provides insights into the use of MPC to manage actual SAGD operation.
Interpreting Distributed-Temperature Measurements in Deepwater Gas-Well Testing: Estimation of Static and Dynamic Thermal Gradients and Flow Rates
Authors: Kabir C.S.. S. , Yi X.. , Jakymec M.. , Hasan A.R.. R. 
Published: March 2015

Summary
In typical drillstem testing (DST), transient pressures are gathered downhole while rate measurements occur at the surface. Effects of heat transfer on pressure, particularly during a buildup test in a gas well, necessitate the close proximity of pressure measurements to the point of fluid entry. While pressure measurements are reliable with sufficient resolution in most settings, rate measurements often lack synergy with pressure because of the sensor resolution and the frequency of monitoring. The reduced-rate sensor resolution and rate-monitoring frequency may precipitate significant uncertainty in transient-test interpretations.
This paper presents a case study for a deepwater asset in Western Australia, where, in addition to the traditional downhole-pressure and surface-rate measurements, temperatures were recorded at various depth stations in four wells, each in a different reservoir, before, during, and after transient testing. These temperature data allowed estimation of gas-flow rates. The computational accuracy of flow rates increased at shallower depths because increased heat transfer, leading to larger temperature difference, enhanced the fidelity of measurements. Overall, the distributed-temperature data allowed the estimation of temperature gradients, including their nonlinear trends, for both the static geothermal and dynamic flows.
A Probabilistic Methodology To Evaluate the Cost Efficiency of Rigless Technology for Subsea Multiwell Abandonment
Authors: Moeinikia F.. , Fjelde K.K.. K. , Saasen A.. , Vrålstad T.. , Arild Ø.. 
Published: March 2015

SummaryIn a few years, there will be a need for performing a considerable number of subsea plug-and-abandonment (P&A) operations on the Norwegian continental shelf. There are certain challenges associated with this. These include more-difficult access to subsea wells compared with ordinary platform wells, high daily rates of semisubmersible rigs, and the fact that these rigs will be allocated for drilling new exploration-and-production wells to sustain the hydrocarbon production. At the moment, there is large focus on finding rigless technologies to reduce P&A cost and use of rig time. A probabilistic approach should be used to assess the cost- and duration-saving potential of such technologies relative to semisubmersible rigs.In this paper, we will consider rigless technologies for performing parts of the P&A operation. For the first time, a probabilistic approach, including learning curves, correlations, and possible risk events, is used to evaluate subsea batch-operated P&A.A realistic example that includes the use of a semisubmersible rig for batch-operated P&A of subsea production wells is used to show how a probabilistic methodology can be implemented for obtaining probabilistic estimates of P&A cost and duration. Inclusion of learning curves and correlations makes the application of a probabilistic approach for multiwell campaigns challenging. It is demonstrated how to incorporate learning curves, correlations, and possible risk events to capture a realistic range of cost and duration for multiwell P&A operations. In a second operational example, a light-well-intervention vessel is used to accomplish preparatory work and wellhead cutting and removal for P&A of the subsea production wells in batch campaigns. These two scenarios will be compared from a cost and duration point of view. Moreover, the advantages associated with riserless technologies for multiwell abandonment are discussed.
Reservoir Simulation, Ion Reactions, and Near-Wellbore Modeling To Aid Scale Management in a Subsea Gulf of Mexico Field
Authors: Mackay E.J. , Jordan M.M. , Ishkov O. , Vazquez O. 
Published: March 2015

SummaryThis paper presents the findings of a study into the impact of reservoir flow behavior on the scaling risk at production wells and the options for managing this scaling risk for a deepwater sandstone reservoir in the Gulf of Mexico. One significant feature in this field is that flow takes place through isolated formation layers, and choices made regarding the seawater-injection wells have a great impact, not only on the barium sulfate (BaSO4) scaling tendency, but also on the placement of scale-inhibitor squeeze treatments in the producers. In addition to seawater injection, oil production is supported by the aquifer. The first stage of this study involved identifying the split between connate water, aquifer water, and seawater in the produced brine. This provided data that could be used to calculate the evolution of the scaling risk over the life cycle of each well. The formation brines contained barium, the injection water was full-sulfate seawater, and the relative proportion of brine (the water-production rate, pressure, and temperature conditions) determined the scaling risk. The evaluation of the extent of reactions between the injection water (sulfate) and formation water (barium) from injection to production well can result in a significant reduction in the available barium within the produced water, and hence, the scaling risk and scale-inhibitor concentration required for prevention of scale deposition. In this study, because the injection wells were completed with inflow-control valves (ICVs), the opportunity was given to manage the injection split by means of these ICVs, not only to improve sweep efficiency, but also to balance reservoir pressures and make squeeze treatments more efficient. This study will present the squeeze-treatment volumes and estimated treatment lifetimes possible for two scenarios for the water-injection application to this deepwater field. The implications of this type of study will be highlighted in terms of the options that these data will allow an operator to consider before commissioning water injection in these challenging environments.
Diagnostic Fracture Injection Tests: Common Mistakes, Misfires, and Misdiagnoses
Authors: Barree R.D.. D. , Miskimins J.L.. L. , Gilbert J.V.. V. 
Published: March 2015

SummaryOver the last 20 years, diagnostic fracture injection tests (DFITs) have evolved into commonly used techniques that can provide valuable information about the reservoir, as well as hydraulic-fracture-treatment parameters. Thousands of tests are pumped every year in both conventional and unconventional reservoirs. Unfortunately, many tests that are pumped provide poor or no results because of either problematic data acquisition or incorrect analysis of the acquired data.This paper discusses common issues and mistakes made while acquiring DFIT data. Guidelines on how to avoid these errors and secure the best possible data are provided, including data resolution, pump rates, test duration, and fluid selection. Strategies are provided to estimate the time required to reach fracture closure and establish stable reservoir transients for analysis.The last part of the paper addresses potential (and commonly observed) problems in the analysis of the DFIT. These issues can be magnified in tight-gas and shale reservoirs because of the long data-acquisition times and the subtle pressure transients that can occur. Specific issues that are discussed include poor instantaneous-shut-in-pressure data from perforation restriction, loss of hydrostatic head, gas entry and the resulting phase segregation, the use of gelled fluids, and errors in after-closure analysis.
A New Comprehensive Model for Predicting Liquid Loading in Gas Wells
Authors: Luo Shu , Kelkar Mohan , Pereyra Eduardo , Sarica Cem 
Published: March 2015

Summary
Liquid loading, which can lead to rapid gas-rate decline and can even cease gas production, is a common phenomenon found in most mature gas wells. An accurate prediction of the inception of liquid loading is of great interest to operators, for the reason that remedial measures can be applied in a timely manner to prevent such conditions from being realized, thereby extending the production life of the gas well. However, the mechanism that is responsible for liquid loading still remains controversial. In the literature, at least three different definitions of liquid loading exist. The first definition is based on the intersection of inflow and outflow curves, the second definition is based on the reversal of entrained liquid droplets, and the third definition is based on the reversal of liquid film. These definitions yield different results when predicting the inception of liquid loading. In this paper, a new definition of liquid loading is introduced. This new definition is based on the relative contributions of gravity and residual pressure drop, and it is validated by its agreement with air/water experimental data.
A new comprehensive model is developed that is based on the Barnea (1986, 1987) model. For vertical wells, the new model can better predict the inception of liquid loading than the widely used Turner et al. (1969) equation. For deviated wells, it is observed in the field and in laboratories that liquid loading starts much earlier than in vertical wells, and most liquid-loading equations are not appropriate for deviated wells. The new model takes into account the nonuniform film thickness around the circumferential position of the pipe, and, thus, it improves the prediction of liquid loading in deviated wells. The new model is validated through the use of field data in the literature and experimental data obtained at the University of Tulsa. In addition to the literature data, a new set of field data is reported and used to validate the new model, which shows a significant improvement over the droplet model as well as other film models.