bluuebunny/crossref_metadata_2025_split huggingface dataset:
Measuring Interwell Communication Using the Capacitance Model in Tight Reservoirs
Authors: Mirzayev Mammad , Jensen Jerry L. 
Published: April 2016

Abstract
The Capacitance Model (CM) has been used to analyze flow rates to measure interwell connectivity (IWC). Numerous case studies show the CM can successfully predict production and identify flow paths and barriers in conventional reservoirs. The challenge is to extend the CM to perform as well in tight reservoirs, which includes fields with high well densities. Fields with such large numbers of wells creates the need to perform IWC evaluations over small regions, called windows, to speed computation and preserve the accuracy of estimates. Windowing, however, creates a problem in that wells within the window may be in communication with wells outside the window. The contribution of the outside wells can be significant and affect the IWC estimation. A CM modification is described which has a ‘pseudo well’, decoupling the outside wells from the window and accounting for varying parameters embedded in an estimate in low permeability reservoirs.
We tested the new model with numerical simulation cases. The CM accuracy (ie simulated vs CM-predicted production rates) is very high (R2&gt; 0.98) for both cases with balanced injection/production and those with local imbalances. The errors (RMSE) of the modified CM-predicted production rates are one-half the unmodified CM errors..
In the Cardium East Pembina field, we used the modified CM to analyze several areas having differing amounts of conglomerate and hydraulically fractured wells. IWC evaluations included areas with wells which were fractured after several years of production and we could therefore compare the pre-fracture IWC with the post-fracture IWC values. The IWC results clearly show elevated connectivities reflecting the presence of conglomerate. The model also captures differences between pre- and post-fracturing connectivities. The direction of the largest IWC change agrees with the expected maximum stress (fracture) direction (NE-SW) in the Western Canada Sedimentary Basin. The matches to measured production are very good, 0.76 &lt; R2 &lt; 0.95.
With the new method, we do not need to include all nearby wells in the window and it tolerates the changes in an estimate accounting for the storage effect and long production well shut-in periods during analysis (tshut-in &gt; 12 months). Due to the windowing capability, the method also enables us to make local IWC evaluations accurately in large tight reservoirs where injectors might have a similar injection profile. The field data illustrate the method's utility and insights it brings.
A Non-Damaging Friction Reducing Agent for Slick-Water Fracturing
Authors: Ibrahim Ahmed F. , Nasr-El-Din Hisham A. , Rabie Ahmed , Lin Genyao , Zhou Jian , Qu Qi 
Published: April 2016

Abstract
Friction reducers (FRs) are crucial components in any slickwater fracturing fluid. Revising the previous literature showed that the majority of research focused on evaluating the friction-reduction performance of these chemicals. Another important aspect, which a few studies addressed, is the potential damage friction reducers can cause, especially to low-permeability formations.
Friction reducers are polymeric in nature (typically polyacrylamide); therefore, they can either filter out onto the surface of the formation or penetrate deeply to plug the pores. Breaking these polymers at temperatures lower than 200°F remains a challenge. This work evaluates a non-damaging and breakable friction reducer that can be a replacement for liner gel with enhanced proppant-carrying capacity.
Friction-reduction performance, proppant settling, breakability, and coreflood experiments were conducted to investigate the new friction reducer (FR1) in terms of friction-reduction, breakability, and the potential damage it might cause to tight sandstone cores at 150°F. The results of the new friction reducers were compared against two conventional friction reducers; one polyacrylamide-based (FR2), and one guar-based (FR3). Different breakers were used to examine the breakability performance; ammonium persulfate (APS), sodium persulfate (SPS), hydrogen peroxide (H2O2), and sodium bromate (SB).
The friction reduction of the new chemical was always higher than 65% in both fresh water and 2 wt% KCl. The presence of calcium chloride did not affect the friction-reduction performance, compared to performance reduction in the cases of FR2 and FR3. The presence of 1 gpt of different types of breakers did not affect the friction-reduction performance, even for stronger breaker (friction-reduction performance was 67% with APS breaker comparing to 68.5 % with no breaker). The new friction reducer is easily breakable in the three tested breakers: ammonium persulfate, sodium persulfate, and hydrogen peroxide. Among the three, ammonium persulfate was the most efficient breaker. Static and dynamic proppant settling tests indicated a superior performance of FR1 compared to the other conventional friction reducer (FR2). Coreflood experiments showed that the new friction reducer FR1 did not result in any formation damage with APS breaker at low KCl concentration (5 wt%) and high KCl concentration (20 wt%). A 9% formation damage was observed at weaker breaker (SB), comparing to 47 and 41.5% damage when the other two conventional friction reducers FR2 and FR3 were tested, respectively. The proposed friction reducer has higher friction-reduction performance and better proppant-carrying capacity with no formation damage compared to the conventional friction reducers.
Conductor-Soil Interaction in Wellhead Motion (WHM) of Platform Wells
Authors: Sathuvalli U. B. , Suryanarayana P. V. 
Published: April 2016

Abstract
During production in prolific high temperature (HT) platform wells, the forces exerted by the inner strings can cause noticeable Wellhead Motion (WHM). The thermal forces created by the inner strings are balanced by the conductor (structural casing), and finally by the friction between the conductor and the formation. Depending on the shear stress profile at the conductor-soil interface, the point of fixity (POF) of the structural casing may lie below the mudline (ML), and gross motion in the subterranean section of the conductor can occur. When the shut-in well cools back to the undisturbed state, the thermal forces disappear. Due to the anisotropic nature of the frictional forces, the wellhead does not always return to its original position, and a fraction of the overall wellhead (WH) displacement is locked in at the mudline. This phenomenon recurs during subsequent production and shut-in cycles and it can lead to ratcheting. Ratcheting becomes a critical issue when the net thermal force on the wellhead is an appreciable fraction (or exceeds) the pullout capacity of the pile.
Current models to assess WHM regard the inner casings as elastic springs that are attached between the wellhead and the POF. The conductor-soil interaction or the casing-cement interaction below the POF are traditionally addressed by a finite element analyses (FEA). In this paper we discuss the importance of the anchoring shear stress at the conductor-soil interface and provide methods to assess its orders of magnitude. We present solutions to frequently encountered problems in operational and design situations where sections of casing below the assumed TOC come loose or when the subterranean motion of the conductor is appreciable. These solutions can be used in lieu of FEA. By coupling the results of this model with the t-z response of pile driven conductors (as per API RP 2GEO), we present semi-analytical models that are applicable in a wide variety of wellhead loading situations.
Pseudo Density Log Generation Using Artificial Neural Network
Authors: Long Wennan , Chai Di , Aminzadeh Fred 
Published: April 2016

Abstract
Reservoir characterization is often a demanding and complicated task due to the nonlinear and heterogeneous physical properties of the subsurface environment. Those issues can be overcome accurately and efficiently by the use of computer-based intelligence methods such as Neural Network, Fuzzy Logic and Genetic Algorithm. This paper will describe how one integrates a comprehensive methodology of data mining techniques and artificial neural network (ANN) in reservoir petrophysics properties prediction and regeneration. Density log, which acts as a powerful tool in petrophysical properties indication, is often run over just a small portion of the well due to economic considerations, the borehole environment or operation difficulties. Furthermore, missing log data is common for old wells, and wells drilled by other companies. Working towards a resolution to these challenges, we will demonstrate successfully constructed automatic system which includes well logging data preprocessing, data mining technologies and ANN prediction. Based on one field case study, this methodology was proficient and stable in pseudo-density log generation.
Analytical Modeling of Flow in Highly Disordered, Fractured Nano-Porous Reservoirs
Authors: Albinali Ali , Ozkan Erdal 
Published: April 2016

Abstract
Conventional porous-medium-flow models are not suitable for naturally fractured, nano-porous reservoirs where the conditions of the continuum assumption do not hold. Due to the abrupt pore-scale variations and severe contrast between matrix and fracture characteristics, the velocity fields over nano-porous unconventional reservoirs display sharp discontinuities and irregular fluctuations. These heterogeneous velocity fields cannot be represented by Darcy's Law, which relates fluid velocity to an instantaneous, local pressure-gradient. An alternative approach is to use anomalous diffusion over a highly heterogeneous velocity field. This paper considers transient, single-phase production from a fractured horizontal well in an unconventional reservoir and uses anomalous diffusion to represent flow in the naturally fractured region between hydraulic fractures. The anomalous-diffusion model combines a time-fractional flux law and classical mass balance to describe sub-diffusive flow in natural fractures, in matrix, or both. The solution of the model is obtained within the framework of fractional calculus. Comparison with established and published solutions shows excellent agreement. Sensitivity analyses indicate that the proposed model can be used to describe a wider range of flow heterogeneity without need for the intrinsic details of the matrix and natural fracture properties.
Girouxville East Montney Waterflood
Authors: Pyo David , Pyo Ken , James Erin , Alwast Norbert 
Published: April 2016

Abstract
This paper presents the design, current status and future expansion plan of the waterflood scheme in the Girouxville East Lower Triassic Montney reservoir, which is located about 350km north-west of the city of Edmonton, Alberta, Canada (Figure 1). The Girouxville East Montney reservoir is a structural trap and is composed of predominantly marine interbedded shales, siltstones and dolomitic sandstones. The reservoir produces 30 – 32 °API crude oil and is a saturated hydrocarbon system with an up-dip gas cap and a down-dip water zone with unusually long oil-water and gas-oil transition zones. The reservoir was initially developed in the early 1990's with vertical wells targeting the up-dip gas cap. Over the last 4 years the down dip oil leg has been targeted and developed exclusively with horizontal drilling technology coupled with multi-stage hydraulic fracturing. This technology has been instrumental to improve well productivity and oil reserves. However, oil recovery under primary depletion still has been low, often less than 5% of original oil-in-place (OOIP), due in large part to local pressure depletion caused by large reservoir withdrawals including formation water and gas. This sets the stage for improved oil recovery via waterflood.
A small water injection pilot was initiated in October 2013 with a single water injector to alleviate reservoir pressure depletion in the local area. The results were encouraging, and the project has been expanded to a larger scale waterflood scheme in 2015, which currently consists of 6 horizontal producers and 4 horizontal water injectors. A 388 ha (1½ sections) waterflood expansion was designed based on comprehensive geological and engineering evaluations. A detailed geomodel was created with available core data, well petrophysical analyses, horizontal well geologic descriptions and seismic data in the area; the Montney formation was subdivided into 4 coarsening-upward cycles, with 6 facies identified within. Dynamic reservoir simulation was initiated by importing data from the geomodel. Reservoir and well properties were fine-tuned with a high-quality history. Multiple forecast scenarios were run to determine an optimal waterflood recovery scheme.
Within half a year most offsetting oil producers have shown positive response to water injection with an increase in total fluid and gradual decrease in the producing gas-oil ratio (GOR). The oil rate decline has slowed down significantly with anticipated incremental oil recovery of 5 – 7% OOIP over the primary depletion. Further expansion has been identified in the oil-leg of the surrounding sections. The waterflood design will focus on down-dip injection to maintain more gravity stable injection water fronts along the field oil-water contacts for optimum pressure support and oil displacement.
Relative Viscosity of Hydraulic Fracturing Fluids Containing Nanoparticles
Authors: Fakoya M. F. , Shah S. N. 
Published: April 2016

Abstract
The concept of relative viscosity is widely used in literature for describing the rheological behavior of Newtonian and non-Newtonian fluids containing particles. Generally, nanoparticles are used at low concentrations; but Einstein equation hardly predicts the suspension viscosity values. Similarly, equations developed for high particle concentrations hardly made the predictions too. This paper presents the inability of Einstein and Krieger-Dougherty equations in predicting the relative viscosity of surfactant-based fluids (SBF), polymeric fluids, and SBF-polymeric fluid blends.
Concentrations of 5% and 33 lb/Mgal guar were used for the laboratory preparation of SBF and polymeric fluids respectively, and both fluids contained 4% potassium chloride (KCl). Also, the mixture of SBF and polymeric fluids in the ratios of 3:1 (vol.) and 1:3 (vol.) resulted into Blend-A and Blend-B fluids respectively. The addition of 20 nm silica nanoparticles, at concentrations of 0.058, 0.24, and 0.4% wt., to the clean fluids generated the nano-fluids. Rheological data were gathered with Bohlin CS-50 rheometer within a temperature range of 75 to 175 °F.
Silica nanoparticle concentrations of 0.058, 0.24, and 0.4% wt. were converted to 0.0083, 0.034, and 0.055 solid volume fractions respectively. Relative viscosity values could not be predicted using Einstein and Krieger-Dougherty equations. The nano-fluids display both increase and decrease in suspension viscosity; furthermore, their suspension viscosities were dependent on the solids volume fraction, temperature, and shear rate (9 to 1026 sec−1.). Lastly, relative viscosity correlations (that covered the whole range of values for which the experiments were conducted), previously developed by the authors, were included for complementary purpose. The correlations predict the viscosity of nano-suspensions as a function of solid volume fraction, temperature, and shear rate.
This work provides an insight into the behavior of suspension at nano-scale level. The prediction of viscosity of nano-suspensions depends on more than one parameter. Moreover, this study will facilitate the field application of these novel hydraulic fracturing fluids.
Possible Misinterpretations in Well Test Analysis Due to Unfiltered Tidal Signal
Authors: Gowtham T , Rouzbeh G. Moghanloo , Vamsi Krishna B , Srikanth P 
Published: April 2016

Abstract
This paper presents the most common misinterpretations in pressure transient analysis owing to unfiltered tidal signal in well test data. Pressure transient analysis gives reservoir engineers an idea about permeability, different components of skin, reservoir model, as well as reservoir geometry. While collecting downhole pressure data, the reservoir engineer is mainly concerned about pressure changes due to fluid flow in porous media. However, the downhole pressure data is affected by a few unavoidable natural phenomena. One of such natural phenomena is the tidal effect in offshore wells and on-land wells near to the shore. Most of the times tidal signals are filtered with the help of pressure recorded by sub-sea pressure gauges and maritime tide tables. However, when those data are not available, or in case of SRO (surface read-out) without provision for filtering tidal signal, build-up data is analyzed without filtering tidal signals.
This paper discusses how tides with different time and amplitudes effect the interpretation of build-up tests having various QBμkh values. [GR1] Tidal signals that have different amplitudes and time periods were superimposed on pure build-up pressure of infinite acting radial model data, and an interpretation of results were compared.
Our results suggest that the early time region of the pressure build-up is not significantly affected by the tidal signal because of the steep increase in pressure. If the build-up test is continued for a significantly long time, even after pressure stabilization (not practical), tidal signals could be identified on a log-log plot by inverted U shape patterns. However, in the case of build-up studies, which are not sufficiently continued, it is likely that geneous infinite acting reservoirs are interpteted as parallel fault, U shaped fault or closed boundary models.
Several possible misinterpretations owing to the presence of diurnal and semi diurnal tidal signals in build-up data are listed in this paper. It has to be ensured that pressure transient data is free of tidal signal before concluding any boundary presence. Unfilterd tidal signals in the pressure transient data may lead to interpretation of unrealastic boundaries. The outcome of this research will help reservoir engineers avoid misinterpreting pressure transient data.
Cointerpretation of Distributed Acoustic and Temperature Sensing for Improved Smart Well Inflow Profiling
Authors: Bukhamsin Ahmed , Horne Roland 
Published: April 2016

Abstract
Current advances in the well completion technology have allowed for more complex smart well instrumentations with marginal additional cost. As an example, optical fibers can be run along horizontal wells to provide acoustic and temperature data that are distributed both in time and space. With such data at our disposal, an immediate evaluation of the well response is possible as changes in the reservoir or well occur. Most current work in distributed measurements looks at Distributed Acoustic Sensing (DAS) or Distributed Temperature Sensing (DTS) data individually, which limits our inferences about the multiphase flow problem. The objective of this work was to look at the two pieces of data together and determine what improvements can be achieved in multiphase flow problems compared to the conventional methods of looking at each DAS and DTS alone.
The study began by evaluating the performance of DAS in analyzing two-phase flow; a process which begins by extracting the speed of sound within the fluid medium from the acoustic signal, then obtaining the phase fraction combination that obtains this speed of sound reading. Another procedure is explained to obtain similar results from DTS measurements. In this case, however, the in-situ phase fractions are correlated to the Joule-Thomson effect as reservoir fluids enters the wellbore. As both these procedures are limited to one- and two-phase flow applications, we extended the solution to work in three-phase flow problems by combining information from DAS and DTS.
The flow profiling procedure was applied to two smart wells in the Middle East. Flowrates from different segments of the well were calculated and results were in close agreement with a surface flowmeter for most sections of the well. In cases where both DAS and DTS were not available for the same well, a commercial compositional and thermal reservoir simulator was used to generate synthetic examples. By applying the developed procedure, we found that cointerpretation of DAS and DTS data yields accurate in-situ three-phase fractions for all ranges of water cuts and gas volume fraction. In comparison, analyzing DAS or DTS individually is usually not sufficient to fully determine a three-phase flow problem.
Nanotechnology Improves Wellbore Strengthening and Minimizes Differential Sticking Problems in Highly Depleted Formations
Authors: Al-Haj Hussain , Al-Ajmi Abdullah , Gohain Ashis Kumar , Al-Rushoud AbdulAziz , Khatib Faiz Ismail , Soliman Ahmed Hussein , Al-Mujalhem Manayer , Fathallah Mohamed Omar , Ibrahim Ahmed Samir 
Published: April 2016

Abstract
It is a challenge to drill in highly deviated or horizontal holes with high differential pressures. Wellbore instability, differential sticking and mud loss are frequently encountered problems while drilling slanted wells in Kuwait across shale and sand series. Drilling became more challenging with considerable non-productive time. Therefore, it is necessary to identify a fluids solution when other options with casing zone isolation are not viable. Traditionally, oil-based mud (OBM) was used while drilling these formations with limited success.
A customized fluid system was designed to overcome the issue of high overburden pressure in shale and sand series formations targeting effective bridging, minimizing pore pressure transmission, and strengthening the wellbore. A nano-size deformable synthetic polymer, along with sized calcium carbonate and graphite, was identified to effectively plug the pore throats and minimize fluid invasion, which was confirmed by particle plugging tests.
A well section was identified to comingle the highly depleted and pressurized formations. This was the first attempt on a high-angle well with development drilling operations in Kuwait and was performed to facilitate the successful drilling of the reservoir. Traditional OBM was converted to a customized fluid system using a nano-size polymer and sized bridging additives based on proprietary software selection and a series of laboratory tests. Drilling and logging were successfully performed for the first time in the commingled section without incident. There was no wellbore instability or differential sticking tendencies, less torque and drag, as well as enhanced wellbore cleaning in the high-angle sections.
This paper also presents some successful applications of the nano-size deformable polymer in OBM to drill highly depleted formations in HTHP wells managing up to 3500 psi overbalalnce across highly permeable formations.