bluuebunny/crossref_metadata_2025 huggingface dataset:
Functional Characterization of Outer Membrane Proteins (OMPs) in Xenorhabdus nematophila and Photorhabdus luminescens through Insect Immune Defense Reactions
Authors: Darsouei Reyhaneh , Karimi Javad , Dunphy Gary
Published: April 2019

Xenorhabdus nematophila and Photorhabdus luminescens are entomopathogenic symbionts that produce several toxic proteins that can interfere with the immune system of insects. Here, we showed that outer membrane proteins (OMPs) could be involved as virulence factors during bacterial symbiont pathogenesis. Purified OMPs from bacterial culture were injected fifth instar larvae of Spodoptera exigua Hübner. Larvae were surveyed for fluctuations in total haemocyte counts (THC), granulocyte percentage (cellular defence), protease, phospholipase A2 (PLA2), and phenoloxidase (PO) activities (humoral defence) at specific time intervals. Changes in the expression of the three antimicrobial peptides (AMPs), cecropin, attacin, and spodoptericin, were also measured. Larvae treated with both types of OMPs had more haemocytes than did the negative controls. OMPs of X. nematophila caused more haemocyte destruction than did the OMPs of P. luminescens. The OMPs of both bacterial species initially activated insect defensive enzymes post-injection, their activating fluctuated in different ways. Attacin, cecropin and spodoptericin were up-regulated by OMP injections more than in normal larvae. The expression of these three AMPs was maximal at four hpi with P. luminescens OMPs treatment. Expression of the three AMPs in X. nematophila treatment was irregular and lower than in the P. luminescens OMPs treatment. These findings provide insights into the role of OMPs of entomopathogenic nematode bacterial symbionts in countering the physiological defenses of insects.
Understanding Flow Through Interwell Tracers
Authors: Tello Bahamon Cristhian Camilo , Mora Gisela , Acosta Tito Jose , Manrique German Alberto , Quintero Diego Fernando
Published: April 2019

This paper presents the successful implementation of an interwell tracer program performed in a multilayered reservoir with mature waterflooding. The objectives of the program are to evaluate water channeling in a high water cut field and, assess sweep efficiency improvements in an EOR pilot test. An extensive methodology was prepared to ensure the quality of the program. The first stage followed the screening of areas and reservoir layers with underperforming waterflooding. After that, the design stage included a selection of tracer available in the market, volume calculation and breakthrough time simulations. The execution plan defined the optimum injection rates, equipment and lab tests requirements for the monitoring and field sampling schedule. The results were being recorded in a monthly progress report and analyzed by a technical team in charge of the project. Interwell tracers made possible to confirm water channeling issues and provided information about the severity of preferential flow using the breakthrough times obtained for each reservoir layer. It was also possible to observe how changes in injection rate impacted the recovery of the tracers, creating different flow patterns at different flow rates. The six-month monitoring ended with the estimation of channel volume to design water conformance treatments. In addition, the findings from the interwell tracer conducted in the EOR pilot test showed an increase in the breakthrough time after three years of polymer flooding and, a change in flow patterns that allowed the displacement of previously bypassed oil. These results are interpreted as a measurable improvement of sweep efficiency and served as input to appraise the performance of the pilot test.
First Ever Polymer Flood Field Pilot - A Game Changer to Enhance the Recovery of Heavy Oils on Alaska’s North Slope
Authors: Dandekar Abhijit , Bai Baojun , Barnes John , Cercone Dave , Ciferno Jared , Ning Samson , Seright Randy , Sheets Brent , Wang Dongmei , Zhang Yin
Published: April 2019

The development pace of Alaska's vast, 20-25 billion barrels, heavy oil resources has been very slow due to high development costs and low oil recovery using conventional waterflood, and the impracticality of deploying thermal methods due to the presence of continuous permafrost. Although, polymer flooding has attracted attention and has become a promising EOR technique in heavy oil reservoirs due to the extensive application of horizontal wells and advancement of polymer flooding technology, no field tests have been performed to date in Alaska's underdeveloped heavy oil reservoirs. The overall objective of this research is to perform a field experiment to validate the use of polymer flooding for extracting heavy oil in Alaska's challenging environment.

Two pre-existing pairs of horizontal injection and production wells in an isolated fault block of the Schrader Bluff heavy oil reservoir at the Milne Point Field are currently being used for the field experiment. Hydrolyzed polyacrylamide (HPAM) polymer injection started on August 28, 2018 at 600 ppm (4 cP viscosity) concentration ramping up to 1,800 ppm (45 cP viscosity) over a three week time period, and has been maintained at an average concentration of ~1,800 ppm. Current injection rates in the two horizontal injectors are ~2,200 and 600 bwpd. Laboratory experiments to determine the polymer retention, optimum water salinity, synergistic effects of water salinity and polymer, and handling of produced fluids, in support of the field experiment, are currently ongoing. Similarly, reservoir simulation of coreflood behavior and history match of previous waterfloods to predict polymer flood performance in the project area are also conducted in parallel.

The field data and scientific knowledge that have been collected since the start of the injection indicates that the field pilot is performing as predicted. To date, no unexpected injectivity issues or polymer breakthrough have been encountered, and the two horizontal producers are showing positive response to the polymer injection, resulting in incremental increase in oil production rate. Since the research is still in its early stages, selected field, laboratory and simulation results are presented and discussed to highlight the integrative approach adopted in this first ever polymer flood field pilot in Alaska.
Modeling Naturally and Hydraulically Fractured Reservoirs with Artificial Intelligence and Assisted History Matching Methods Using Physics-Based Simulators
Authors: Eltahan Esmail , Yu Wei , Sepehrnoori Kamy , Kerr Erich , Miao Jijun , Ambrose Ray
Published: April 2019

Unconventional reservoirs typically exhibit large uncertainty in rock and fracture properties coupled with significant heterogeneity making manual history matching a challenging endeavor. Computer-assisted methods of history matching gained preference because they honor the non-uniqueness of the possible geological and fracture realizations by allowing efficient simulation sensitivities over many possible outcomes. This study integrates EDFM's fracture-modeling capabilities into an artificial intelligence-based history matching and optimization tool, to achieve more confidence and capability in simulations for production forecasting and reservoir-behavior studies.

This approach involves four main steps: (1) initializing EDFM-fracture parameters for a realization, (2) running a pre-simulation command that calls the EDFM-preprocessing engine and generates an updated model, (3) running the model on an appropriate simulator, and (4) calculating the objective function. We apply this method to perform history matching for a horizontal tight-oil well in the middle Bakken. We further repeat history matching for the same model after including a set of 1,000 randomly distributed natural fractures. In both studies, four embedded-fracture parameters are set to vary within predefined continuous ranges.

The objective is to minimize history matching error for field-recorded, bottom-hole pressure and gas production data with oil production history set as a constraint. This new method, with a more realistic fracture geometry, resulted in a better match to the field-recorded data compared to a previous study that was based on a local gird refinement model. After introducing natural fractures to the model, history-matching results displayed a trend of decreasing rock-matrix permeability and fracture conductivity compared to the original scenario without natural fractures. In this case, history matching error response was most sensitive to rock-matrix permeability followed by fracture half-length. We then made 30-year production forecast using the most optimal solutions. Accepted solutions were screened based on a cut-off value of 5% normalized history-matching error. We finally demonstrate that, even though the presence of natural fractures significantly altered the model, it did not have a major influence on long-term production.
A Robust Reservoir Screening Approach to Identify IOR/EOR Opportunities from Mature Oilfields
Authors: Chen Peila , Zhu Yidan , Deka Anisha , Kuma Chandan , Kuma Manish , Balasubramanian Sriram , Thakur Ganesh
Published: April 2019

The paper demonstrates a robust and efficient screening workflow and methodology that identifies reservoir candidates for improved oil recovery/enhanced oil recovery (IOR/EOR) methods. This workflow integrates rigorous analysis of production/injection data with understanding of reservoir geology and petrophysics. Firstly, based on screening criteria including reservoir properties and volumetric estimates, the reservoirs were studied and ranked. The screening study was supported by incorporating the evaluation of geological framework, facies distribution, and flow barrier. Secondly, the reservoir drive mechanism was investigated through MBAL study. Thirdly, various production performance plots were generated to evaluate waterflood performance. The diagnostic plots included hydrocarbon production rate, water injection rate, gas oil ratio (GOR), number of active oil producers versus time; and water oil ratio, hydrocarbon production rate, water injection rate versus cumulative oil. The ABC (after before compare) plot was also analysed to identify the regions for IOR/EOR opportunity. Simple gas/chemical EOR feasibility studies were also performed based on reservoir static and dynamic data available.

Fifty (50) mature oil reservoirs were ranked and the high potential reservoirs for IOR/EOR were identified. Considering gas EOR opportunity, the key parameter under study was the minimum miscibility pressure (MMP), mobility ratio, GOR and reservoir pressure. Diagnostic plots were generated to assist in the analysis of waterflood response. A plot of water oil ratio with cumulative oil led to a conclusion to maintain the WOR to follow a specific trend. The time needed to re-pressurize a reservoir was considered in addition to evaluating geological heterogeneities and sand continuity to determine if certain IOR methods will be effective and economic. Through this workflow, additional IOR/EOR opportunities were identified to increase production and/or extend the reservoir life. The reservoir analysis has indicated the reservoirs under study have a high side opportunity of adding over 5.4 MMKLS of recovery through effective reservoir management.

The waterflood performance review and IOR/EOR screening workflow incorporates geological aspects along with static, dynamic, and operational parameters, which is appropriate for a large number of reservoirs underconsideration. These insights, evolved from practical field experiences, are beneficial for revitalizing mature water floods, and more importantly the design and implementation of suitable EOR pilots.
Model Evaluation of Sand Transport Under Gas-Liquid Stratified Flow
Authors: Dabirian Ramin , Mohammadikharkeshi Mobina , Mohan Ram , Shoham Ovadia
Published: April 2019

Sand transport in multiphase flow has recently gained particular attention of many companies in oil and gas industry owing to unpleasant circumstances that particle deposition accompanying. The main objective of this study is to evaluate the performance of some existing models for the prediction of the critical sand deposition velocity under gas-liquid stratified flow against acquired experimental data.

Experimental data are acquired under stratified flow regime with the air as gas phase, and the water as liquid phase. Spherical glass bead with three particle sizes of 70, 185 and 510 μm with concentrations less than 0.0045 vol/vol are utilized as solid phase. A horizontal 0.1 m ID test facility is designed and constructed in order to investigate the effects of parameters such as phase velocities, particle concentration and particle size on the critical sand deposition velocity. The acquired data are compared with previous models developed by Salama (1998), Stevenson and Thorpe (2002), Hill (2011), Ibarra et al. (2014) and Dabirian et al. (2017) to determine the most reliable model for the prediction of the critical sand deposition velocity.

The experimental data show that depending on the particle size and concentration, the critical velocity can change either linearly or exponentially with particle concentration. The evaluation of the previous models with acquired experimental data confirm that Ibarra et al. (2014) and Dabirian et al. (2017) models generally show better performance for the predictions of the critical velocity. Models proposed by Salama (1998) and Hill (2011), respectively, under-predicts and over-predicts the critical velocities under various experimental conditions. Also, the comparison of Stevenson & Thorpe (2002) model and the experimental data corroborates that the model is not an accurate predictive tool for the critical velocity.
Analytical Model of Fault Leakage in Compartmentalized Reservoirs Considering Three-Directional Flow in the Fault Zone
Authors: Mosaheb Mojtaba , Zeidouni Mehdi
Published: April 2019

Faults are planar interfaces that intersect the sequential sedimentary layers and may provide a hydraulic connection between the confined layers. Early warning of undesirable fluid leakage into the shallower formations is important in geological storage/disposal operations. Pressure pulses travel fast and carry information that is directly related to the fluid movement through the media. In this study, we provide an analytical model to evaluate the pressure perturbation of fault leakage into a shallower layer. The solution is derived by coupling the fluid flow equations of the two layers as well as the planar interface of the fault. Results show that the solution is useful for interpretation of the pressure variations to identify the anisotropic fluid flow through the fault. The solution can be applied to separately evaluate leakage to the other side of the fault and the above layer as well as the horizontal leakage along the fault plane.
Integrated Workflow Reduces Uncertainty in Type Well Construction and Production Forecasting of Multi-Fractured Horizontal Wells
Authors: Lemoine Romain , Lee John
Published: April 2019

A common purpose of type wells is to predict the production profiles of multi-fracture horizontal wells (MFHW) in a selected geologically similar area (GSA) in a resource play. This paper presents a unique workflow that leads to type well production forecasts as analytically scaled rate-time profiles for an identified range of reservoir and completion properties.

The workflow uses production data from all MFHW's in a GSA to build more representative type wells. First, we sort and bin the wells, accounting for observed flow regimes (transient and boundary-dominated flow). We then extract physical properties from the data using curve-matching techniques. Using these properties, we can forecast the production profile of any well already in BDF. For wells still in the transient flow regime and for undrilled wells, we probabilistically forecast performance using distributions of observed properties (such as permeability and fracture length) from existing wells in BDF and Monte Carlo simulation.

We demonstrate that the analytical scaling factors resulting from type-curve matching can be used to construct a probability distribution of production forecasts from type wells. We can scale the type well production profiles to a given set of reservoir and completion properties, including observed average sets of properties from well analyzed or based on altered completion designs. We illustrate the workflow with a data set of 126 MFHW gas wells in the Denton County, Texas, Barnett shale. Using information extracted from this data set, we forecasted production for undrilled wells and validated the forecasts using a sequential accumulation plot with information from10 analog wells.

Type wells are important tools for decision makers and engineers to determine economic feasibility of proposed development projects and estimate reserves. As opposed to purely empirical methods used for type well construction, our analytically-based workflow provides an integrated GSA characterization, reliable production forecasts and better tools for decision making with reduced uncertainty.
A New Analytical Model to Predict Oil Production for Cyclic Steam Stimulation of Horizontal Wells
Authors: Chen Fangxuan , Liu Huiqing , Dong Xiaohu , Wang Yanwei , Zhang Qichen , Zhao Dandi , Gai Pingyuan , Yin Fanghao , Qu Li
Published: April 2019

For cyclic steam stimulation (CSS) process of horizontal wells, previous studies mainly focused on the shape of heating zone and few scholars took heat losses from upper and lower reservoir rocks into consideration. However, it is hard to accurately describe the shape of heating zone accounting for steam override and boundary shielding effect. And on-site production cares more about the heating volume and efficiency which determine the cumulative oil production rate. As a result, the object of this paper is to propose an accurate and computationally efficient method for calculating heating volume and oil production rate.

In order to precisely describe the heating zone, a scaling factor, M0, is introduced to coordinate the maximum and minimum heating volume. The maximum heating volume is calculated by assuming there is no heat loss from upper and lower reservoir rocks while the minimum heating volume is demonstrated by assuming the heat losses from an equivalent vertical well. Besides, time-dependent average temperature, pressure and saturation are included to demonstrate steam override effect. Instead of using conductivity equation, frictional pressure loss from toe to heel is solved by an iteration scheme.

Results of this model are compared with results simulated from commercial software Computer Modeling Group, STARS. Daily oil production rate exhibits good agreement between the proposed model and STARS. Different thermal conductivities and diffusivities of sandstone, shale rock and limestone are considered to expand the application of this model. Moreover, different values of M0 are calculated for further validation. This thermal model can be an effective predictor for planning heavy oil field development.
A Modified Design for Gravel Packing with Expandable Rubber Beads
Authors: Ramezanian Mahdi , Emadi Hossein , Wang Hong
Published: April 2019

In oil and gas wells with sand control completion, during gravel pack installation and production life of the well, void spots - known as hotspots - may form in gravel packs. Hotspots provide permeable channels within the pack that allow sand to pass into the wellbore and consequently loosen the pack. Finding an innovative way to prevent hotspots from forming maintains the gravel pack integrity and preserves its efficiency. Indeed, this approach would save money by reducing the demand for remedial operations. This paper introduces, a modified design for gravel packing with expandable rubber beads. The new pack is composed of gravel and expandable rubber beads rather than 100% gravel and is capable of avoiding the hotspots and maintaining pack tightness. A series of experiments were conducted, with diesel, on 100% expandable rubber bead packs and mixtures of gravel and bead to measure their swelling capacity and permeability. The swelling volume was evaluated to assess the beads capacity to fill the hotspots and permeability was measured to assess their potential to create flow barrier. The tests show promising permeabilities for gravel/rubber bead packs and reasonable expansion potential to fill the hotspots. Increasing the proportion of the beads in gravel/rubber bead mixture pack, results in very low permeability. Hence, finding an optimum proportion of rubber beads is essential to designing a pack that will take advantage of their swelling capacity to avoid hotspots while retaining reasonable permeability toward the flow.
Impact of Frac Hits on Production Performance- A Case Study in Marcellus Shale
Authors: Khodabakhshnejad Arman
Published: April 2019

A new approach is proposed to quantify the communication between wells in a tight multi-layered shale gas reservoir. In this approach, a wide range of data sets, from microseismic monitoring to the production data are analyzed to evaluate the communication between wells in every stage of well development. The results provide new insight into how the initial well communication during stimulation impacts the well interference during production.

Microseismic data collected during hydraulic fracturing are analyzed for a three-well pad drilled in the Appalachian basin. The microseismic event locations, magnitudes, and fracture plane characteristics are used to construct a discrete fracture network (DFN). The permeability of a numerical reservoir model is calculated from the generated DFN, and the model is further integrated with available reservoir data. History matching is carried out using three years of production data to calibrate the reservoir model, which was also used to predict water and gas production for thirty years. Finally, decline curve analysis (DCA) is used to examine the production behavior of the reservoir.

The microseismic data monitored during hydraulic fracturing show the presence of communication between wells in the pad. This communication, also known as frac hits, is established as more events are recorded in the offset wells, indicating the extent of hydraulic fractures. In addition, the pressure perturbation in the offset wells confirms the presence of a pathway connecting the wells during stimulation. Furthermore, the reservoir model built in the numerical reservoir simulator shows overlap of drainage volumes. In the reservoir model, the depleted region expands across multilayer formations in both lateral and vertical directions. An analysis of the production behavior of the wells using DCA suggests an almost logarithmic trend which is expected for these types of reservoirs. Surprisingly, detailed analysis of the results reveals there is no significant deviation in the overall performance of wells associated with well interference, especially in the early years of production. However, at greater than 10 years of production, the expansion of the depleted zone accelerates the well interference which leads to lower performance of the pad in the long term. The results demonstrate that the enhanced permeability zones created due to frac hits may not have an immediate impact on production performance.

Traditionally, frac hits and well communication were considered damaging to the reservoir production. However, this new result shows that the well communication during fracturing may not impact short-term production. Additionally, it highlights the importance of a thorough examination of the fracture network along with the reservoir properties to evaluate the potential impact of frac hits on reservoir production.
A Prediction Method for Estimating Time to Convert From Cyclic to Drive in Steam Injection Processes
Authors: Ssembatya Henry , Ershaghi Iraj
Published: April 2019

There is significant history on the use of steam injection processes in California heavy oil reservoirs. In this paper, we introduce a graphical method for estimating the optimal timing of conversion from Cyclic Steam Stimulation (CSS) to steam drive and compare our estimation to actual cases where CSS had continued with the buildup of significant water saturation around the wellbore. We use as a measure, the SOR (Steam Oil Ratio) to ascertain the optimality of the conversion points and compare it to our modeling work. During the CSS process, steam injectivity is gradually improved, resulting in low SOR which is the characteristic of the steam stimulation process. We see of course some relation between the behaviors of various oil viscosity types and the SOR during CSS. But in general, the rapid heating of the formation relates to limitations associated with contact volume. Based on our numerical modeling, we demonstrate that a log-log plot of cumulative injection vs. cumulative production for all the cycles leads to a linear relationship. When there is an indication of flattening of oil steam ratio or an increase in SOR, it is time to change to steam drive allowing the steam to contact a larger volume of the reservoir. Thus, the heat-scavenging effects of water buildup around the injection well and low relative permeabilities of oil traveling through the high water saturation interval are avoided. The estimated SOR during the CSS process depends on the oil viscosities and vertical conformance. The optimum time corresponds to the point where there is deterioration of the SOR. We showcase studies on several CSS wells from fields in Central California validating the graphical method and demonstrating the steam savings had the proposed timing been implemented. The methodology presented confirms a practical and smart way for operators to decide on the conversion timing.
Synergistic Effect between Surfactant and Nanoparticles on the Stability of Methane Foam in EOR Processes
Authors: Qian Chen , Telmadarreie Ali , Dong Mingzhe , Bryant Steven
Published: April 2019

The major challenge in enhanced oil recovery (EOR) by gas injection is poor volumetric sweep efficiency, mainly due to the high gas mobility and reservoir heterogeneity. Injecting gas as a foam increases sweep efficiency, but maintaining foam stability within the reservoir remains a challenge. This research evaluates the synergistic interaction of one type of nanoparticle and a surfactant to increase foam stability, using the concentration ratio of the two components to tune the affinity of the nanoparticle for the gas/liquid interface. We test the capability of the synergistic two-component system to stabilize methane foam and compare it with foam stabilized by surfactants only. A key distinction is the foam stability upon contact with oil, and we explain the observations in static and dynamic conditions.

Foam stability was measured both in static (foam height) and dynamic (flow through porous media) conditions. In the static test, foam is generated by the shaking method, and foam texture (bubble size and shape) and the decay of foam height with time are indicators of foam stability. To test static stability in presence of oil, heavy oil is injected into the foam-liquid interface. In dynamic test, foam is pre-generated before flowing at elevated pressures into sandpacks containing various oil saturations. Normalized pressure gradient, and apparent viscosity are the indicators of foam stability and effectiveness for improving oil recovery.

The extent to which nanoparticles are covered with surfactant governs the foam stability both in static and dynamic conditions. Static foam is stable in the presence of oil only if the nanoparticles are partially covered by the surfactant. In the dynamic test, foam stabilized with the only surfactant collapses in the porous media when oil is present. Nanoparticles alone could not generate foam regardless of the presence of oil, but foam stabilized with nanoparticles partially covered by surfactant is stable in the presence of both residual and initial oil. In both static and dynamic conditions, nanoparticles completely covered with a bilayer of surfactant do not stabilize foam in the presence of oil. Partially covered nanoparticles foam also demonstrated salt tolerance in both static and dynamic test. Thus at appropriate surface coverage, the combination of nanoparticles and surfactant is more effective than either stabilizer alone.

The result shows that surfactant and nanoparticles interaction is important in foam stability in the porous media with oil. In particular, this interaction is synergistic at certain coverage. This type of synergy can provide much more robust mobility control for EOR processes involving gas injection.
Further Investigation of Downhole Heating by an Electric Cable
Authors: Medizade Mason M. , Wiltshire Zach
Published: April 2019

Heat is an important component in heavy oil production. One method includes generation of electric current using solar panels or other methods and converting electricity into heat for surface or downhole applications via an electric cable. The heat can help removal of paraffin, wax or hydrate in the production tubing, removal of heat sensitive skins in and around perforations and reduction of oil viscosity in the reservoir zone. The objectives of this study are to present the results obtained from a finite element model study including the cable, well, and the reservoir. Reported results are in continuation of our previous study reported in SPE-185736-MS in 2017. The study uses a commercial finite element model. The model consists of the production tubing, cable, well and the porous media as the reservoir zone. The wellbore fluid is different gases or mostly water. The cable is attached to the production tubing's sides and immersed in well fluid in different lengths. The model solves the two-dimensional heat of conduction equation providing same temperature distributions obtained from other analytical methods. Following parameters are changed using a fixed cable heat density, W/m: well fluids, length of cable immersed, cable orientation, cable lengths, reservoir thermal conductivity and reservoir porosity. The finite element model runs are obtained for vertical well at different model mesh sizes. The best results were reported. In case of stagnant gas surrounding the electric cable, the sand face of the well heats up very quickly. However, transfer of heat up to many meters into the reservoir continues at a slower pace. Similar results are obtained for both vertical as well as horizontal wells. Thermal conductivity of the porous media and its specific heat and density plays an important role in heat transfer and distribution in the reservoir zone. If water is surrounding the cable and given its thermodynamic states of pressure and temperature is allowed to reach near boiling, the heat transfer to the reservoir naturally can be accelerated due to initiation of latent heat of vaporization and its transfer to the reservoir. This study will present all the new finite element runs obtained and the temperature distributions as a function of time and radial distances into the reservoir. Heat is always needed in production of heavy oils worldwide and specifically in California as steam injection faces its own operational challenges. The technology of electric heating needs to be understood and cables needed to be designed properly and effectively. If that happens many deeper and larger heavy oil zones can be produced more economically. Like other similar studies, this study will help design evolution needed for more rugged and robust and effective downhole heaters.
Evaluation of Gas and Downhole Water Sink-Assisted Gravity Drainage GDWS-AGD Process in Saturated Oil Reservoirs with Infinite-Acting Aquifer
Authors: Al-Obaidi Dahlia A , Al-Mudhafar Watheq J , Wojtanowicz Andrew K , Al-Jawad Mohammed S , Saini Dayanand
Published: April 2019

A hybrid Gas-Enhanced and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) process has been suggested to enhance oil recovery by placing vertical injectors for CO2 at the top of the reservoir with a series of horizontal oil-producing and water-drainage wells located above and below the oil-water contact, respectively. The injected gas builds a gas cap that drives the oil to the (upper) oil-producing wells while the bottom water-drainage wells control water cresting. The hybrid process of GDWS-AGD process has been first developed and tested in vertical wells to minimize water cut in reservoirs with bottom water drive and strong water coning tendencies. The wells were dual-completed with 7-inch production casing and 2-3/8 inch tubings and perforated above the oil-water contact (OWC) for oil production and below OWC for water drainage. The two completions were hydraulically isolated inside the well by a packer. The bottom (water sink) completion drained water with a submersible pump.

The GDWS-AGD was efficiently adopted to improve oil recovery at the PUNQ saturated oil field. The PUNQ Field has an infinite active aquifer with very strong edge and bottom water drives. A black oil reservoir flow model was implemented for CO2 flooding simulation of the GDWS-AGD process in comparison with the Gas-Assisted Gravity Drainage (GAGD) process. The comparison was performed to obtain the clearest image about the performance of the combined GDWS-AGD process. Next, Design of Experiments (DoE) and proxy modeling were incorporated to find the most sensitive parameters that affect the GDWS-AGD process performance. The candidate parameters are porosity, horizontal and vertical permeability for each layer, radius of aquifer and rock compressibility.

In the GDWS-AGD, the produced water not only reduced water cut and coning, but also significantly reduced the reservoir pressure, resulting in improving gas injectivity. In addition, the GDWS-AGD process improved cumulative oil production. More specifically, the results showed that cumulative oil production increased from 3.8*105m3 to 4.7*105m3 and water cut decreased from 97% to 92% in all the horizontal oil producers. For the proxy model, it was cleared from Sobol analysis that the porosity for layer 5 was more influential parameter than others on cumulative oil through GDWS-AGD process with 31% main effects and 0.025% interaction effects, while the horizontal permeability for layer 4 was the most influential parameter with 24% main effects and 1.5% interaction effects. The novelty of GDWS-AGD process comes from its effectiveness to improve oil recovery with reducing the water coning, water cut, and improving gas injectivity. This leads to more economic implementation, especially with respect to the operational surface facilities.
Pitfalls of Surface Well Test Analysis - Guidelines
Authors: Hakim Bilal , Fair Chris
Published: April 2019

Pressure Transient Analysis (PTA) provides valuable information about the subsurface completion and reservoir. Permanent downhole pressure gauges (PDHG) are not always available in wells. In such cases, wellhead pressure (WHPG) gauges, or temporary downhole gauges (DHG) can be used to perform reservoir/completion diagnostics. Although in some cases it is safe to use raw WHP data for analysis, in a lot of cases it should not be done. Fair et al. (2002) presented a methodology to categorize wells that could be tested from the surface (well head) along with a methodology that allows surface-to-bottomhole pressure (BHP) conversion.

A few authors in the past have emphasized the importance of converting wellhead pressure and downhole gauge pressure data to mid-completion bottomhole conditions to account for friction and changing fluid density during a test. Performing PTA without correcting the gauge data for these wellbore effects can lead to inaccurate results: especially the over-estimation of skin and permeability, and underestimation of P*, and in-place hydrocarbon volumes, due to reservoir signal suppression. The WHP data could also be non-analyzable (using conventional methods) if the effects are severe. Hakim et al. (2016) further discussed the importance of this conversion and presented examples where WHP to BHP conversions in various types of wells could be performed with high accuracy using a coupled PVT-thermal wellbore model.

This paper will introduce the concept of rate of change in wellbore fluid density (wellbore signal) relative to the rate of reservoir pressure increase/decrease (reservoir signal) during a test. The purpose is to identify the factors affecting the "reservoir signal" in the measured wellhead pressure and rate data during a well flowback and during the commercial production period, and to provide guidelines to help the petroleum engineer determine the severity of these factors in a given well/reservoir system. This should help the petroleum engineer in deciding whether to rely on the WHP data or run a DHG to observe the reservoir signal.

A 3-step methodology to determine the magnitude of the wellbore signal relative to the reservoir signal will be presented with solved examples of an oil well and a gas-condensate well.
Permeability and Porosity Evolution of Organic Rich Shales as a Result of Heating
Authors: Kim Tae Wook , Ross Cynthia M. , Guan Kelly , Burnham Alan K. , Kovscek Anthony R.
Published: April 2019

Source rocks (oil shale) were matured artificially via pyrolysis under geologically realistic triaxial stresses using a unique coreholder that is compatible with X-ray Computed Tomography (CT) scanning. This study focuses on characterization of porosity and permeability as well as the evolution of shale fabric during pyrolysis. Experiments were conducted using 1-inch diameter vertical and horizontal core samples from the Green River Formation. Prior to pyrolysis, the properties of the source rock were characterized (e.g., porosity, bulk density, mineralogy, and TOC). Samples were then heated from room temperature to 350 °C under a nitrogen environment to obtain conversion of organic matter to oil and gas via pyrolysis. Porosity and permeability after maturation were measured. Micro-CT visualization was applied to investigate the fracture network developed throughout the core. Scanning electron microscopy (SEM) images were also used to compare the shale fabric and porosity evolution (pre- to post-maturation) at higher resolution.

In-situ observations reveal a decrease of average CT number (i.e., density) within some volumetric regions of the cores after maturation. In these regions, organic matter (kerogen and bitumen) were converted into hydrocarbons. Changs in the source rock depends on the original TOC fraction, hydrogen index (HI), and temperature. The permeability prior to pyrolysis for vertical samples is in the undetectable to nanodarcy range. The permeability of all cores increased to the microdarcy range post-maturation. In particular, the permeability of the horizontal sample increased from 0.14 to 50 μD. This improvement in permeability occurred due to the generation of open porosity and fractures (dilation, generation, and/or drainage). Additionally, the porosity after Soxhlet extraction increased proportionally by 20 % from pre- to post-pyrolysis depending on pyrolysis time and TOC fraction. Longitudinal deformation depends on the orientation of the sample with respect to the triaxial stress during pyrolysis. The deformation of vertically oriented samples with isostress conditions is larger than that of horizontally oriented samples with isostrain. The measured 3D in-situ porosity distribution indicates that organic matter has transformed into hydrocarbons by pyrolysis. The development of a fracture and matrix porosity system under stress provides an explanation for transport of hydrocarbon away from its point of origin.
Case Study: Natural Gas Storage in Federal Waters Offshore California
Authors: Ojukwu Chima , Smith Kevin , Kadkhodayan Nadia , Leung Mark , Dame Robert , Voskanian Armen
Published: April 2019

The U.S. Pacific Outer Continental Shelf (OCS) Region offshore California has over fifty years of production and development history. As of 2018, more than 1.35 billion barrels of oil and 1.85 trillion cubic feet of natural gas has been produced from three sedimentary basins in the Pacific OCS1. As part of the Bureau of Ocean Energy Management's (BOEM) mandate to sustainably manage development of U.S. OCS energy and mineral resources in an environmentally and economically responsible way, it is paramount that conservation and mixed-use projects such as underground gas storage be evaluated, adjudicated, and monitored to maximize utility of existing OCS offshore infrastructure. Through 2018, only a few underground gas storage projects have been undertaken in the entire U.S. Outer Continental Shelf (OCS) federal waters. The Sockeye Field Underground Gas Storage project in the Santa Barbara channel is a unique example of alternative reservoir use, as it is the only such project initiated and successfully executed in the Pacific OCS Region. Gas injection commenced short-term in 2002 and was effectively formalized in 2005 through an agreement between the Sockeye Field Operator and BOEM's predecessor agency, the Minerals Management Service (MMS). From the inception of the project through 2017, total gas volume injected and withdrawn was 2.3 Bcf and 582 Mcf respectively.

This paper presents the results of the reservoir modeling study prepared for the Sockeye Field gas storage project. In this integrated study, BOEM utilized available 3D post stack time-migrated seismic reflection data, digital well log data, production data, and other geologic information to develop a comprehensive structural and petrophysical model of the Sespe sandstone reservoir. This study scrutinized segmentation of the Sespe hydrocarbon reservoir and, the suitability of the Sespe reservoir for storage of produced natural gas from the Sockeye Field.

Frhe results of the reservoir modeling, operator's cumulative gas production and injection indicate this gas storage scenario provided an energy source for offshore facility operations, precluded the need for external gas buy-back, and lengthened the productive life of the Sockeye Field. In addition, this project also demonstrated that nearby analog reservoirs in the Pacific OCS may be suitable for future underground gas storage.
Fall-off Diagnostic of Eroded Zones during Waterflooding of Unconsolidated Formations
Authors: Qi Qianru , Ershaghi Iraj
Published: April 2019

Development of thief zones has been of concern in waterflooding of oil reservoirs. In this paper, we focus on the gradual erosion of unconsolidated sandstones under waterflooding. Such high permeability intervals may grow laterally and eventually lead to the development of thief zones. Early detection of these washout intervals is essential. The profile surveys may help in detecting such intervals, but the focus here is an early warning approach from a correct analysis of fall-off tests that relates to intervals affected by the onset of erosion by the injection water.

We have developed a new analytical solution and have conducted a series of numerical experiments to examine the presence of eroded intervals. Our studies show various solutions presented in the literature use the model of a horizontal fracture in tight rocks. We believe these models are not applicable to eroded intervals in unconsolidated formations when the host rock offers significant permeabilities to the injection fluid. Various pressure transient solutions to the pancake-shaped or horizontal fractures proposed by several investigators such as Gringarten and Ramey (1971) and Valko and Economides (1997) are not applicable to eroded intervals in unconsolidated formations. For tight host rock, these solutions indicate linear flow or certain transition periods that are not applicable to the solution observed in unconsolidated formations, embedded with the horizontal eroded zones.

Based on our work, eroded intervals in unconsolidated formation manifest a radial flow regime with high permeabilities on fall-off tests. This can sometimes mask the buildup of injection water-related skin on the host rock. We tested our methodology for a series of fall-off tests in a waterflooding where the associated profile surveys indicated the development of thief intervals. In all cases, we were able to detect radial flow.

For the first time, we are presenting a new approach for monitoring eroded intervals from pressure fall-off tests and are pointing out the deficiencies of using existing horizontal fracture solutions for tight host rocks to high permeability eroded intervals in unconsolidated formations.
Coupled Geomechanical Modeling to Assess Cap Rock Integrity and Mechanical Fault Stability: Application to Farnsworth Field Unit Project
Authors: McMillan Marcia , Will Robert , Ampomah William , Balch Robert , Czoski Paige
Published: April 2019

The SWP project is located in a mature waterflood undergoing conversion to CO2-WAG operations in the Farnsworth, Texas, USA. Anthropogenic CO2 is sourced from a fertilizer and an ethanol plant. This work utilizes Farnsworth’s full-field, history-matched, compositional hydrodynamic coupled geomechanical model for assessing the impact of stress changes observed through the history matched field life. Production and injection induced stress changes, fault stability and caprock integrity investigations are performed to project the potential for fault reactivation and the loss of caprock integrity under shear failure.

A static mechanical earth model (MEM) was constructed for use in transient coupled geomechanical model based on the existing Southwest Regional Partnership (SWP) geological model. The static MEM inherits the stratigraphic and structural features of the geologic model and incorporates additional overburden, underburden, and sideburden formations required to impose mechanical boundary conditions. Mechanical properties were distributed in the 3D MEM through integration of geophysical logs and 3-dimensional seismic elastic inversion properties using a combination of Bayesian and stochastic interpolation methods. These data are further enhanced by lab derived strength and failure criteria for the caprock interval. Additionally, interpreted faults and other geological features were included as part of the static structural framework to fully represent subsurface hydraulic and mechanical systems and appropriately integrate heterogeneity. Two-way coupling of hydrodynamic flow and geomechanical simulations incorporates the Kozeny-Carman relationship for updating permeability and is history matched through primary, secondary (waterflooding) and tertiary (CO2 WAG) recovery periods before performing a twenty year forecast.

Two-way simulations are performed to understand the effective stress perturbations imposed by field operations: water injection and the more recent implementation of WAG. Evaluation of Mohr circles with liquid production and field pressure charts as well as slip tendency and distance to failure metrics indicate that neither our faults or cap rock are critically stressed. This paper presents the results of the Farnsworth initial attempts to integrate the seismic driven 3D MEM into coupled hydrodynamic geomechanical history match simulation workflow.