bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation of Flow in the Solid Matrix of Shale Reservoirs using Lattice-Boltzmann Method
Authors: Tarakanov Alexander , Gildin Eduardo , Nasrabadi Hadi
Published: April 2016

The economic success of the shale boom worldwide is intimately connected to the effective stimulation of the tight (or very low) permeability rock through multistage hydraulic fracturing of horizontal wells. However, the complete understanding of the production mechanisms in shale reservoirs (micro to macro scales) and the closely interaction between natural fractures and the overall production profile at reservoir scales are in the infancy stages of their developments. In this paper we are particularly interested in extending the robustness and computational effectiveness of the Lattice Boltzman Method (LBM) applied to fractured porous media simulation. In this paper we propose a novel approach for modeling of shale reservoirs can seamless integrate rock-fluid behavior at small scales with the well-reservoir interaction at macro scales. This is done by exploring further the advantages of physical-based premises of the LBM by including the recent developed non-uniform induced permeability field concept in order to simulate fracture media, which model variation of permeabiliry around hydraulic fracrures by a function of the distance away from the fracture. In our numerical studies, based on a single well reservoir with a planar fracture, we indicate that this approach is more consistent with the physics of shale production, as it does not rely on such formulas as Langmuir isotherm and Klinkenberg's formula, which have been originally derived for low-density gases.
Geochemical Interpretation and Field Scale Optimization of Low Salinity Water Flooding
Authors: Nguyen Ngoc T. , Dang Cuong T. , Nghiem Long X. , Chen Zhangxin
Published: April 2016

Low Salinity Waterflooding (LSW) is an emerging Enhanced Oil Recovery (EOR) method. Wettability alteration towards increased water wetness in LSW is the widely accepted mechanism for the enhanced oil recovery. This phenomenon can physically be explained by ionic exchanges and geochemical reactions. However, the detailed ion exchanges have never been adequately addressed, and the explanations provided in the literature are sometimes contradictory leading to challenges of a successful LSW design. This paper aims to: (1) present detailed ion exchanges and geochemical reactions that happen in LSW using a compositional simulator; (2) analyze the key factors that affect an ion exchange process and address how to maximize the preferable wettability alteration; (3) investigate the potential of combining CO2 with LSW (CO2 LSWAG) to promote geochemical reactions and maximize the final oil recovery factor; (4) conduct a robust optimization of CO2 LSWAG under geological uncertainties.
An Application of the Isogeometric Analysis Method to Reservoir Simulation
Authors: Lynd Eric A. , Foster John T. , Nguyen Quoc P.
Published: April 2016

The isogeometric analysis method (IGA) has been an emerging technique for exact geometrical discretization and efficient high order approximations in the field of computational engineering. While its potential has been demonstrated in a variety of disciplines, it has yet to be applied extensively to the field of reservoir simulation. This work shows IGA's potential as a useful tool for next generation reservoir simulation, highlighting its ability to exactly capture complex-shaped geometrical features in the reservoir and, consequentially, accurately model the pressure fields. First, an IGA code is validated against the analytic solution for a quarter five-spot pattern as well as a reference solution for a straight line source problem with pressure enforced at the corners of the domain. Next, the numerical efficiency of IGA is compared against a finite element method solution of single phase flow in a 2D representative reservoir containing a centralized "S-shaped" line source. Results suggest a clear advantage of the IGA method over the classical finite element method, which has lower convergence rates in terms of number of degrees of freedom.
Coupling of Darcy's Equation with Molecular Transport and its Application to Upscaling Kerogen Permeability
Authors: Kou Rui , Alafnan Saad Fahaid , Akkutlu I. Yucel
Published: April 2016

Quantification of gas transport in organic rich shale is important in determining natural gas production rates. However, laboratory measurements are challenging due to very tight nature of the rock, and have large uncertainties due to presence of multiple mechanisms of gas transport at multiple pore scales. In this paper, the emphasis is on the understanding of transport inside organic material known as kerogen and prediction of its permeability.

We performed nonequilibrium molecular dynamics simulations of steady-state methane flow in single-wall carbon nanotube based on a moving piston model (Riewchotisakul and Akkutlu, 2015). The piston model allows us to observe transition from convection to molecular (pore) diffusion under the reservoir conditions and to understand the effects of adsorbed methane molecules on the overall transport in the tube. The results show that the adsorbed molecules are not only mobile but also contribute a significant portion to the total mass flux. Simulations with different sizes of capillaries show that the contribution is profound in capillaries with diameter less than 10nm. The adsorbed-phase transport velocity is independent of capillary size, but strongly dependent on pressure drop across the capillary. This allowed us to formulate the transport as an additional diffusion mechanism by the capillary walls using a modified Hagen-Poiseuille equation and predict the transport enhancement.

In the second part of the paper, we considered steady-state transport across a pore-network of inter-connected nano-capillaries. The preliminary simulation results show that the modified Hagen-Poiseuille equation leads to representative elementary volume of a model kerogen. The estimated permeability of the volume is sensitive to surface properties of the nanocapillary walls indicating that fluid-wall interactions driven by molecular forces could be significant during the large-scale transport within kerogen. A modified Kozeny-Carmen correlation is proposed.
The Impact of Rock Properties on Acid Jetting in Carbonate Rocks: An Experimental Study
Authors: Ndonhong V. , Belostrino E. , Zhu D. , Hill A. D. , Beckham R. E. , Shuchart C. E.
Published: April 2016

Acid jetting, as a well stimulation method for carbonate reservoirs, has shown optimistic results in the production enhancement of some extended reach horizontal wells. It was used initially to promote damage removal along a wellbore via multiple strategically-located injection nozzles. It has the potential to place the injecting fluid at the locations that need stimulation. Jetting may also enhance wormhole propagation compared with conventional matrix acidizing. These hypotheses are currently being investigated to improve the design for more efficient stimulation treatments.

We have conducted an experimental study to investigate the effect of jetting on wormhole efficiency. The jetting experiments are conducted at a constant pressure with linear core-flood tests, where a stand-off distance is maintained between the injection nozzle tip and the core. At low-velocity acid injection, jetting effectively removes mud filter-cake by mechanical actions. Jetting also creates wormholes in carbonate cores. The combination of mechanical and chemical reactions stimulates carbonate rocks better than matrix acidizing without the jetting nozzle. When the jetting velocity increases, the dissolution pattern changes. An isolated locally compact dissolution results in a cavity at the entries of core samples by jetting, followed by a wormhole structure. With the known dissolution pattern, sensitivity studies are carried out to investigate the effect of various parameters on the experimental outcome.

We used Indiana and Winterset limestone rocks in the experiments. 15% HCl (by weight) at ambient temperature was used and the core dimensions were 4 inches in diameter and 16 inches in length. Various combinations of acid jetting velocities and acid fluxes were considered. The Winterset limestone cores are more heterogeneous, with higher porosity and lower permeability than the Indiana limestone cores. From the experimental results, the results of acid jetting from the two different rock samples are compared.

The experimental results indicate that acid jetting follows the same trend as matrix acidizing regarding wormhole propagation once cavities are created. Jetting velocity and acid flux are the critical parameters in jetting design for optimal stimulation results. Acid jetting tends to create different dissolution patterns for Indiana limestone and Winterset limestone cores. The observations from this work highlight the importance of understanding the dynamic chemical process of jetting in the design of successful acid stimulation jobs.
Comparative Study of Acid Fracturing and Propped Hydraulic Fracturing for a Tight Carbonate Formation
Authors: Suleimenova A. , Wang X. , Zhu D. , Hill A. D.
Published: April 2016

Acid fracturing is one of the methods for well stimulation in carbonate formations. Compared to propped hydraulic fracturing, acid fracturing takes a simpler procedure, and therefore, usually with a lower cost. On the other hand, fracture conductivity is more difficult to maintain, especially in formations that have high closure stress. In this study, a procedure is developed to evaluate the feasibility of acid fracturing by comparing conductivity generated from an unpropped fracture, a propped fracture and acid fracture. The target formation features extreme closure stress and low permeability at a depth of 5000-7000 meters. The efficiency of acid fracturing is challenged by the severe condition of the formation.

The laboratory experiments were performed using the core samples from three wells from the productive interval of the target reservoir. The acid fracturing treatment conditions that have been used in the field were simulated during the laboratory experiments. The fracture conductivity was measured for un-propped, acid-etched, and propped fractures at different closure stresses using an apparatus consisting of a modified API conductivity cell and a load frame The fracture face surface of the intact and acidized core samples was scanned with a profilometer to characterize the change in surface profile to calculate the volume of dissolved rock caused by acid etching, and the initial fracture conductivity under zero closure stress. Conductivity decline as a function of closure stress was recorded and examined during the study.

The results of the comparative study on fracture conductivities showed that the final propped fracture conductivity was higher than the acid fracture conductivity for all of the core samples. Also, the rate of conductivity decline with increasing closure stress was lower for the propped fracture conductivity compared to the acid fracture conductivity. The conclusion was made that the propped hydraulic fractures would retain a greater conductivity under the formation closure stress compared to the acid fractures. Hence, the hydraulic fracturing with proppant would be a more effective stimulation treatment compared to the acid fracturing for improving the wells productivity for the studied reservoir.
Case Study of a Super-Giant Field Rejuvenation
Authors: Li Yong , Li Baozhu , Liu Lang , Xiong Lihui , Luo Hong , Peng Hui , Wang Daigang
Published: April 2016

Many oilfields in the world are mature and developed at the later stages of their life, and how to rehabilitate these fields is the biggest challenging problem. This paper presents an integrated approach with multi-disciplines to rejuvenate one of the world's super-giant oilfields in Middle East.

The K super-giant oilfield have more than 60 years' production history. Current oil recovery of the field is over 50% with more than 60% prolonged shut-in wells, and higher than 10% annual decline rate. The proposed integrated rejuvenation approach involved the analysis of comprehensive multi-disciplines, from geology and reservoir engineering understanding, to completion, stimulation, and surface facilities analysis. And based on the analysis results, shut-in wells are ranked into different types respectively, different treatments are applied according to well rank. Production rate of producing wells are optimized based on integrated models. New well candidates and other well work are also proposed.

For K oilfield, prolonged shut-in wells are classified into 4 ranks by principal component analysis, which mainly based on the understanding from bottom hole pressure evaluation, remaining oil description, offset well performance analysis, status of surface facilities, etc. Wells of rank 1 can be potentially open blowing directly with oil rate higher than 3000 mbd, and wells of rank 2 need install new ESP for artificial lift with oil rate only between 2000 mbd and 3000 mbd. While wells of rank 3 have much surface facilities problems and much lower potential oil rate, and wells of rank 4 have no potential to re-open. Also, an integrated model with subsurface, wellbore and surface facilities combined are established for production optimization. Based on the model, performance of producing wells can be analyzed, and flowing path or linkage pipeline of some wells were changed in order to meet the potential capacity of the well and surface facilities. Infilling well candidates are selected through pressure and remaining oil distribution analysis, which are mainly placed at the crest areas. Furthermore, other well works such as re-perforating, sidetracking, are also implemented with successful results.

This study details a successful application of an integrated field rejuvenation approach for a super-giant field, which stabilized the production of the field at the first year and made a 10% production rate increment for the second year. Most importantly, the methodology presented can be adopted in other similar mature fields.
Channel Fracturing Technology Provides an Effective Solution to Unlock Tight Gas Development and Production Potential in Saudi Arabia
Authors: Rahim Zillur , Al-Kanaan Adnan , Kayumov Rifat , Al-Jalal Ziad , Fredd Chris
Published: April 2016

Economic recovery and production of non-associated gas from the tight clastic reservoirs in Saudi Arabia faces some challenges resulting from high bottomhole temperature, high in-situ stress, low permeability, and high Young's modulus and rock compressive strength. Hydraulic fracturing, a necessary means to exploit the tight reservoirs, encounters constrains such as high fracture initiation and treating pressure, risk of pre-mature screen-out, and conductivity degradation with time. A conventional fracturing treatment in such challenging environment necessitates increased polymer loading in fracturing fluids to stabilize fluid viscosity and using smaller size proppant at low concentrations to ensure proppant placement. This results in shorter effective fracture half-length and low fracture conductivity. Reduced contact area decreases production potential. Additionally, high polymer loading is not easily breakable and may create major damage to the proppant pack, thereby substantially reducing fracture conductivity. The challenges compound when the reservoir is relatively tight and often cannot generate enough energy to clean up the injected fracturing fluids. To overcome these challenges, channel fracturing was introduced where proppants are added in pulses in fracturing fluids along with dissolvable fibers creating stacks of pillar-like structure inside the fracture. These proppant pillars stay suspended and are held by the fibers during the treatment. Once the pumping is stopped, the fracture closes on the pillars and the fibers degrade under formation temperature. These pillars hold the fracture open and act as columns; the void surrounding them are essentially stable channels along the entire geometry of the fracture that provide open pathway for hydrocarbons to flow in a near-infinite conductivity environment. The technology also reduces the amount of proppant pumped compared to a conventional treatment, and pulsation of proppant during pumping reduces the risk of an early screen-out.
Upscaling WFT Permeability Data: A Systematic Approach to Analyzing and Integrating Well Test Data From Wireline Formation Testers WFT
Authors: Mkhize S. , Aluko A. O. , Gringarten A. C.
Published: April 2016

Permeability is a rock property which measures the ability of a porous medium to transmit fluids and controls the fluid flow direction and rates. Permeability can be obtained from cores, wireline formation tests (WFT), nuclear magnetic resonance (NMR) logs and well tests.

Typical usages of WFT include measuring formation pressures along the wellbore, taking fluid samples, identifying fluid types and evaluating reservoir structure. Occasionally, WFT is used to replace a drill stem test (DST) in an exploration well. As in well tests, WFT data are measured in situ but, whereas well tests provide an average over a larger formation volume, WFT permeabilities are generally associated with a smaller volume of investigation around the measurement depth. A limitation of pressure transient analyses with WFT, however, is that they often only yield spherical permeabilities, due to short radii of investigation resulting from small rates and short pretest durations. In such a case, anisotropy can be obtained from formation rate analysis (FRA). Pressure transients generated during fluid sampling by WFT tools can have longer radii of investigation and reach radial flow.

In this study, pressure transient analysis (PTA) and FRA techniques are applied first to model generated WFT data, then to an actual gas reservoir using invaded zone and formation fluid properties. PTA derived spherical permeabilities and FRA results are then combined to obtain permeability anisotropy and estimate both horizontal and vertical permeabilities versus depth. These are then upscaled to compare with permeabilities obtained from DST’s.

Various upscaling methods were investigated. It was found that (1) weighted arithmetic average upscaling yields the best results for horizontal permeability (within 20% of DST permeabilities), and (2) harmonic averaging of vertical permeabilities gives the best match over a wide range of anisotropy values.

This study confirms that upscaled WFT permeabilities are representative of the formation permeabilities, provided appropriate upscaling methods and fluid properties representative of the test zone are used in the WFT analysis.
Biodegradation Of Hydrocarbons As A Mechanism Of Microbial Enhanced Oil Recovery
Authors: Uzukwu Chukwuemeka , Dionisi Davide
Published: April 2016

Microbial enhanced oil recovery (MEOR) is one of the enhanced oil recovery (EOR) techniques that is applied to oil reservoirs after primary and secondary recovery techniques to increase oil production. The successful implementation of MEOR involves an interdisciplinary approach. This paper has focused on one of such approaches which is the bioengineering aspect of MEOR that is concerned with the quantitative description of microbial growth and yield factors. Early MEOR works have focussed on the use of external carbon sources i.e. carbohydrate nutrients to produce metabolites useful for oil recovery, using the petroleum hydrocarbons present in the reservoir as the carbon source for microorganisms can be essential in microbial enhanced oil recovery as this addresses some logistic problems encountered in adverse environment. The metabolites which are useful in MEOR techniques for oil recovery can be produced by growing the microorganisms on petroleum hydrocarbons. The microbial degradation of n-alkanes and some readily biodegradable substrate has been studied. A simple respirometric method has been developed to assess the biodegradability of these compounds. Initial experiments have been performed in small-scale laboratory bioreactors to determine hydrocarbon degradation rates through oxygen consumption data (under aerobic conditions) collected over a period of time. Analysis of initial kinetic parameters has shown that estimates of hydrocarbon biodegradation based on respirometry is very reproducible with some consistency in the data generated. It has been shown from calculated microbial growth rates that petroleum hydrocarbons can be utilized under aerobic conditions at reasonably rates. The biodegradation of petroleum hydrocarbons using nitrate as electron under anoxic conditions has also been studied.
Shale Reserve Forecasting - Model Consistency and Uncertainty
Authors: Whitson Curtis Hays , Coll Carolina , Dahouk Mohamad Majzoub , Juell Aleksander Oma
Published: April 2016

Three general categories of modeling are traditionally used to provide shale reserve forecasting – (1) decline curve analysis (DCA), (2) rate-time analysis (RTA), and (3) numerical model history matching (HM). The focus of this paper is aligning each of the three modeling approaches to ensure maximum consistency in terms of fundamental reservoir description, including (but not limited to) initial fluid in place, reservoir rock properties, PVT, well completion factors, fracture area and conductivity, well controls, and definition of infinite-acting and boundary-dominated flow regimes. The HM model approach, though more rigorous, is time consuming and cannot be used for the hundreds of wells in a typical shale field. We recommend, as have others, that history-matched numerical models be used to help calibrate RTA and DCA models in a consistent manner for all wells.

Once a consistent model framework is achieved, reserve forecasting can be better understood by regulators, engineering and reserve teams within the operating company and their partners. Furthermore, a consistent modeling framework can provide more reliable uncertainty analysis to establish probabilistic reserves estimates in terms of P90-P50-P10 values (1P-2P-3P).

Modeling methods used in forecasting shale reserves are based on production data that includes rates and pressures. DCA applies the boundary-dominated methods such as Arps, where multiple time regions are used to capture infinite-acting and boundary-dominated flow. RTA uses dimensionless pressure and rate solutions applicable to horizontal wells with multiple fractures, including superposition, pseudopressure and pseudotime. Numerical models solve the complex set of differential equations describing multiphase fluid flow using a properly-selected grid refinement (e.g. near fractures) and, in some cases, a dual porosity/dual permeability treatment of fracture-matrix interaction.
Mechanical Degradation of Polymers During Injection, Reservoir Propagation and Production - Field Test Results 8 TH Reservoir, Austria
Authors: Puls Christoph , Clemens Torsten , Sledz Christoph , Kadnar Rainer , Gumpenberger Thomas
Published: April 2016

The polymer pilot test performed in the 8 TH sandstone reservoir in Austria shows incremental oil production. Soon after increasing oil cuts were detected, polymer was back-produced from the wells which were showing the oil production response. The polymer concentration increased to about 100 ppm in the back-produced water.

Size Exclusion Chromatography was used to determine the molecular weight distribution of the back-produced high molecular weight polymers (HPAM). The results showed that careful sampling is required to avoid degradation of polymers during the sampling procedure. Analyzing pressurized samples revealed that some degradation of polymers from the original average molecular weight of 20 MDa to 8 MDa occurred.

To investigate where in the surface facility-injection-reservoir-production system degradation took place, specific field tests and laboratory experiments were performed.

Chemical and biological degradation was excluded as reservoir conditions are benign (50 °C, 20,000 ppm) and nitrogen blanketing and biocides are used.

At the surface facilities, no degradation was detected. Swabbing and laboratory experiments showed that severe mechanical degradation occurs in injection wells if injection is performed under matrix injection conditions owing to high flow velocities in the near-wellbore. However, induces fractures are substantially decreasing mechanical degradation. To avoid severe degradation of HPAM, the flow velocities in the near-wellbore and related mechanical degradation have to be evaluated and the injection designed accordingly.

In the reservoir, polymers are not degraded as the flow velocities are low.

Sucker Rod Pumps as used in the production wells in the polymer pilot area do not lead to polymer degradation. This means surface polymer samples can be taken to investigate the degradation in the injection well.

Surface sampling has to be performed pressurized to avoid high shear rates and oxygen in the samples.
Integrated Development of Europe's Largest Open-Access Underground Gas Storage by Use of a Multidisciplinary Simulator
Authors: Bruijnen Pieter , Plug Willem-Jan , van Yperen Guido , Botermans Wouter
Published: April 2016

Between 2007 and 2014, TAQA Energy converted the Bergermeer field from a depleted gas field into a gas storage with a working volume of 4.1 billion normal cubic meter (BCM) and a production capacity of over 57 million Nm3/day from 14 wells. During this project, with a CAPEX of more than 800 million Euro (excluding cushion gas and transportation commitments), a tight planning schedule was followed. The schedule required full integration of technical, commercial and economic disciplines and had to follow an operational plan to ensure that the project would be realised on time. In order to deliver the entire system, according to technical specifications and commercial requirements, a pragmatic in-house simulator was developed: GRIP (Gas Re-Injection and Production). The tool is based on nodal analysis and uses the key parameters that would determine the performance of the storage elements. After running multiple realisations an optimum design of the gas storage was selected. During the define, execution and operation stages of the Bergermeer storage, GRIP was also used for further optimisation, forecasting and monitoring of the actual performance. The results show that the tool has been very successful in predicting the storage operational envelope, and that integration between disciplines is the key to the success.
Successful First Multistage Hydrajet Assisted Fracturing Process in an Ecuadorian Mature Field
Authors: Carrión Johana , Herrera Mauricio , Chuc Edgar A. , Chapa Jaime , Hernández Rubys
Published: April 2016

This case history paper presents the first multistage fracture stimulation of a mature field well in Ecuador using a hydraulic workover unit deploying jointed pipe. The process used a hydrajet perforating application followed by tubing-path pumping of the fracturing treatments.

To place fractures properly in each pay zone, effective diversion is required. This has been a challenge in many fields of Ecuador. Furthermore, multistage fracturing completions have represented a complex process when applying conventional methods because of the number of operations involved, such as perforating, fracturing, setting isolation plugs, and cleaning out the wellbore for each interval. Several trips into the well are often required, which adds time and costs to the entire completion intervention.

Because of the absence of some information as well as the presence of upper open perforated intervals, the hydrajet assisted fracturing (HJAF) process, which uses highly effective abrasive jet perforating immediately before the fracturing stage, was used to provide a degree of flexibility for making additional decisions and performing changes during the operation. This paper presents the detailed workover planning, multiple customized fracturing designs, operations data, and the stimulation results of the case study. The multistage hydraulic fracturing technique was designed and applied to individually fracture stimulate three formation layers in the Ecuador mature field. The method allowed using customized treatments for each zone and more aggressive fracturing schedules to promote high fracture conductivity or length when necessary.

Successful production from the mature Ecuadorian field was achieved using the multistage hydraulic fracturing HJAF method. Additionally, this method does not require mechanical zonal isolation between stages. The HJAF technique provides an attractive option for applications in similar wells to help recover additional reserves.
Using Sacrificial Agents to Enhance Surfactant Performance in the Eagle Ford Shale
Authors: He Kai , Yue Zhiwei , Xu Liang
Published: April 2016

Analysis of flowback and produced waters for surfactant residues showed that a majority of surfactants were retained inside the reservoirs (Rane and Xu 2015). While it is beneficial that surfactant typically does not flow back and continues to contribute to production increase, it is uncertain where in the reservoir the surfactant is actually retained or distributed. A plausible mechanism is that most surfactant may plate out prematurely on the formation rock in the near-wellbore (NWB) region, potentially restricting surfactant travel deeper into the reservoir. This paper discusses the study of a solution using a sacrificial agent (SA) to adsorb onto the formation surface which enables surfactants to further penetrate the Eagle Ford (EF) formation during a hydraulic fracturing treatment.

Laboratory testing revealed that injection of 1 gal/1,000 gal surfactant in the presence of 1 gal/1,000 gal SA enabled minimum adsorption of the surfactant on both proppant and formation rocks. Notably, the addition of SAs resulted in lower interfacial tension between fluids and enhanced hydrocarbon solubility. As a result, oil recovery was enhanced considerably. Additionally, approximately 70% friction reduction of the fracturing fluid with surfactant and SA was achieved and fluid stability and compatibility with standard guar-based fracturing fluids was also verified, thus providing compelling evidence for field trials.
Real-Time Integrated Subsurface Analysis to Determine Commerciality of the Pegasus West Exploration Discovery
Authors: Walters S. , Colbeck A. , Godhrawala H. , Trythall R. , Turner V.
Published: April 2016

The Pegasus West (43/13b-7) exploration well was drilled in Q3 2014 with the aim of testing gas presence and quality within the Carboniferous of the Southern North Sea. The overall objective was to assess whether the well was to be suspended for development, saving considerable point forward capex spend. Key to this decision was determining effective gas-in place (GIIP), as bulk GIIP estimations are not a reliable basis for development.

A workflow was put in place before spud with decision points and outcomes outlined, these included: 1) Decision to run core over two prognosed high reservoir quality sandstone intervals. 2) Selection of a wireline programme to deliver critical data over minimal runs. 3) Decision to well test (DST) based upon vertical and horizontal permeability calculations from core and wireline data. 4) Suspend or plugged and abandoned decision through assessment of minimum connected volume (MCV), effective GIIP, and minimum economic field (MEFS) size via DST analysis of individual sandstones.

A balance of minimising well cost without jeopardising the objectives and safety of the project was paramount. Operations were carried out efficiently through conducting static model, petrophysical, DST and economic analysis in-house. New working practices and tools were used within the data acquisition programme to give new insight into reservoir characterisation. A communication plan was established between onshore, offshore, subsurface, drilling, and service companies so all operated smoothly through decision criteria.

Through adopting the workflow the well was drilled within original authorised for expenditure time and budget. All decision points were made successfully, including recovering two cores over the highest quality sandstones, running wireline operations without delays and performing three isolated DSTs with a combined flow rate of more than 90MMscf/d. The MCV gave a low case effective GIIP of 53.4 BScf, which exceeded the MEFS of 40BScf; therefore the well was suspended.
An Innovative Approach for RPM Gel Water Shut-Off Simulation
Authors: Sheshdeh Milad Jokari , Awemo Kilian Nchungong , Yadav Atul
Published: April 2016

Since the potential of relative permeability modifying (RPM) gels for water shut-off was discovered, many researchers focused on understanding the mechanisms by which, these gels perform their disproportionate permeability reduction (DPR) behavior. The focus on this concept and developments in experimental methods and laboratory equipments, have led to clearer and reasonable explanations for the mentioned behavior of these gels. However, the focus on the experimental scope of these gels has resulted in lack of studies on the numerical simulation of the RPM gels injection in the reservoir.

In this paper, it is tried to use the achieved experimental knowledge by the mentioned experiments, to analyze the feasibility of the current approaches and to come up with a new approach.

Polymer option of commercial black oil simulators is the first approach analyzed and it is proved that using this approach results in false prediction of the relative permeabilities in the treated cells after gel adsorption. The reason is the assumption of the simulators about the effect of the polymer adsorption on oil relative permeability reduction.

An alternative to polymer option is defining the gels as solid particles and interpolating the relative permeabilities between the initial and treated sets as a function of the defined solid particles adsorption to the rock surface. Since solid particles cannot be present in the injecting stream, they have to be defined as liquid particles and turned to solid phase in the reservoir via the reactions. Defining reactions necessitates having the simulation in compositional model which is sometimes not favorable due to larger run times and required PVT data for fluid modeling for a compositional run.

Surfactant option has the interpolation capability too and it is run in black oil model. In other words it has the capabilities of the compositional approach, but due to its black oil formulation, run times are shorter and no fluid modeling is required. However, using surfactant option of a simulator, changes the capillary pressure and results in reductions in interfacial tension between oil and water. These EOR effects of surfactant presence in the reservoir has to limited by manipulating the defined functions. The approach is then validated against a single well treatment observed data and could reproduce the observed production rates in the 18 months period after the treatment. Validation of the approach permits us for using this approach to simulate RPM treatments in different scales.
The Komsomolskoye Field - Fast Track Development of a Remote Oilfield Using a Blend of Horizontal and Vertical Wells
Authors: Lechner Michael , Uspanov Marat , Ilchibayeva Aigul
Published: April 2016

This paper tells the success story of the Komsomolskoye field which was brought on stream in 2008, some 24 years after its discovery in 1984. Ramp up of oil production to peak of some 7,000 bopd was achieved within only five years. The field is located in a remote location of Western Kazakhstan - onshore on the Buzachi Peninsula, some 350 km from the regional city of Aktau and 110 km from the nearest village Kyzan. Road access from Kyzan is available only through a gravel road.

The subsurface field development since 2008 consists of five horizontal oil producers, five vertical water injectors and two vertical gas injectors. The horizontal producers contribute the bulk of the field's oil production and were drilled from two well pads due to the semi-offshore nature of the Komsomolskoye field - seasonal flooding restricts access to a large portion of the surface area during half of the year. Produced gas and produced water are re-injected at the periphery of the field for pressure support, in addition to a weak aquifer support. Moreover, additional injection water is sourced from two dedicated shallow water wells and likewise injected into the reservoir. In addition to the five major horizontal producers, there is a pre-2008 well stock of ten vertical producers, which were successfully re-entered and of which eight were brought online to date.

The favourable areal layout of the composite vertical/horizontal pattern plus the improved/enhanced oil recovery effects of water injection and miscible gas injection, respectively are key factors which enabled the following achievements: fast track ramp up of oil production rate to some 7,000 bopd within only five yearszero gas flaring, due to gas re-injection and own consumption for power generationreservoir pressure throughout the field being safely above bubble point pressurea current recovery factor of 12% as of July 2015a projected recovery factor by year 2039 of 36% for a development scenario with no additional wellsa projected recovery factor by year 2039 of some 45% for a development scenario with 5 additional vertical producers

As a case study, this paper illustrates a recent "fit for purpose" development project and may serve as an example for sustainable oilfield development in remote locations. It could be of benefit to organizations and individuals who are involved in the operation of comparable assets.
Unlocking the Potential of Remaining Hydrocarbons Using Time Lapse Pulsed Neutron Capture Logs in Complex Completions - A Case Study from UK Central North Sea
Authors: Ali Arfan , Small Simon , Singh Kamaljeet , Martin Andy
Published: April 2016

Reservoir surveillance using pulsed neutron capture (PNC) sigma data has shown its importance historically (Madhavan et al. 2015; Odom et al. 1994; Gournay and Maute 1982). This paper proposes to discuss the planning, acquisition and analysis of the PNC sigma data in complex well completions with multiple casing strings and hole sizes. A case study from the Gannet A field located in the Central North Sea of the United Kingdom has been presented to demonstrate the importance of having the correct logging environment and its subsequent effect on the PNC sigma processing and interpretation. The consequence of not making such detailed checks may result in mis-interpretation of the sigma data leading to incorrect conclusions about fluid dynamics, and risky decisions in water shut-off (WSO) opportunities and additional perforations. The integration of PNC sigma data with other surveillance techniques such as production logs and 4D seismic has also been discussed to understand the reservoir dynamics for Well Reservoir and Facility Management (WRFM) planning purposes.

The Gannet A field comprises an Eocene age deep marine amalgamated turbidite sand reservoir with combined dip/stratigraphic closure. The field initially had a gas cap and a thin oil rim. In the early 1990’s, eleven horizontal producer wells were drilled to produce solely from the oil rim. Two additional wells were used to re-inject a portion of the produced solution gas into the gas cap. Gas injection ceased in 2001 due to unexpected strong aquifer ingress from the North-East. The oil rim and aquifer moved upwards into the former gas cap in the North resulting in a tilted contact from the North to the South and watering out of the producers progressively over time. The PNC sigma data has played an important role in accessing the migrated oil rim and understanding reservoir movement. In 2015, PNC sigma data helped to add perforations in three wells in the Gannet A field adding approximately 5,000 bbl/d of incremental oil.

This paper focuses on the three key areas in PNC sigma interpretation which are often overlooked. Firstly, quantifying the effect of the type of annuli fill, hole size, and multiple casing/tubing strings on computed saturations; secondly, the importance of using consistent environmental parameters for time lapse comparison of the PNC sigma data; and thirdly, the added uncertainties in computed saturations due to the presence of three fluid phases; i.e. migration of oil rim into the original gas cap and its subsequent sweep with water.
Investing in Technology for More Information - When is it Worth it?
Authors: Wilson Séadhna
Published: April 2016

At any stage of the Exploration and Production cycle decisions must be made with limited information. This situation can always be improved by investing more money or time in improving the quality and variety of information available. However, this in itself presents a decision as to whether the investment to get new information such as a new seismic survey is worth it. This paper outlines a practical and structured method to estimate the value of new information in monetary terms, which can be used to make an informed business decision on whether the new information is worth it.

The method is comprised of two primary elements. Firstly the problem is defined using a decision tree analysis approach that considers what decisions are to be made and their possible outcomes. Secondly, a collaborative workshop is used to estimate the probabilities required to populate the decision tree. This then enables the Expected Monetary Value to be calculated both with and without the technology that acquires the new information. The difference between the two is approximated as the value of the information. This paper uses a case study approach to explain this method that considers an operators dilemma in deciding whether or not to drill an appraisal well.

Obtaining a meaningful result from this process requires time and commitment from management and technical staff. However, at stake are the considerable sums of money in acquiring the new information and the subsequent investment decisions that draw on the new information. The method described as a minimum provides fiscal information to make investment decisions and at best, provides a framework in which the benefits and risks of investing in new technology can be fully understood.

There has already been much published on the use of decision trees to estimate the value of information. However, in practice it can be difficult to estimate the probabilities required for a decision tree analysis to work as they are not intuitive to describing the situation. This approach simplifies this by arranging the mathematics to make the task of the workshops clearer and more achievable. The result is a practical method that can be easily understood and implemented.
Differential Responses to Preemergence and Postemergence Atrazine in Two Atrazine‐Resistant Waterhemp Populations
Authors: Ma Rong , Evans Anton F. , Riechers Dean E.
Published: April 2016

Waterhemp [Amaranthus tuberculatus (Moq) Sauer] is a difficult‐to‐control dicot weed in the United States. Atrazine [6‐chloro‐N‐ethyl‐N’‐(1‐methylethyl)‐1,3,5‐triazine‐2,4‐diamine] is commonly used for preemergence (PRE) and postemergence (POST) waterhemp control in maize (Zea mays L.). Previous research reported that atrazine metabolism via glutathione S‐transferase (GST) activity contributes to atrazine POST resistance in two waterhemp populations from Illinois, designated MCR (McLean County, Illinois, resistant) and ACR (Adams County, Illinois, resistant). Objectives were to quantify responses of these populations to atrazine PRE and determine if the combination of a GST inhibitor and atrazine PRE or POST increases their control. Dose‐response analyses indicated MCR was resistant to atrazine PRE relative to ACR or WCS (Wayne County sensitive; herbicide‐sensitive population), despite MCR and ACR exhibiting equivalent levels of atrazine resistance POST. The ACR response to atrazine PRE (LD50) was intermediate compared with MCR and WCS. Seedling survival of ACR was reduced by 4‐chloro‐7‐nitrobenzofurazan (NDB‐Cl; a GST inhibitor) and atrazine PRE more than atrazine PRE alone, but not in MCR. Atrazine following NBD‐Cl applied POST inhibited seedling growth in ACR, but not in MCR. Enhanced atrazine activity with NBD‐Cl further supports rapid metabolism via GSTs as the main atrazine‐resistance mechanism in ACR. GST(s) that metabolize atrazine in MCR may not have been completely inhibited by NBD‐Cl, indicating that similar yet distinct atrazine‐resistance mechanisms exist in MCR compared to ACR. In conclusion, atrazine PRE (with or without NBD‐Cl) still controls ACR when applied at typical field‐use rates in maize, but the length of residual activity may be shorter than in sensitive populations.

Core Ideas

Two waterhemp populations are resistant to atrazine POST due to increased metabolism by GST enzymes.

Since atrazine can also be soil applied, quantifying the levels of resistance in these populations is important for weed management in maize.

The MCR population was resistant to atrazine PRE and displayed a higher level of resistance to atrazine PRE than the ACR population.

NBD‐Cl, a metabolic inhibitor of GST enzymes, enhanced atrazine activity in the ACR population but not MCR.

The length of residual activity of atrazine may be shorter for controlling these populations in maize compared with sensitive populations.
Ammonia Emission from a Beef Cattle Feedlot and Its Local Dry Deposition and Re‐Emission
Authors: McGinn S. M. , Janzen H. H. , Coates T. W. , Beauchemin K. A. , Flesch T. K.
Published: April 2016

Ammonia (NH3) volatized from livestock manure is affiliated with ecosystem and human health concerns and decreased fertilizer value of manure and can also be an indirect source of greenhouse gas. Beef cattle feedlots, where thousands of cattle are grouped together to enable greater control of feed management and production, are hot spots in the agricultural landscape for NH3 emissions. Quantifying the feedlot NH3 emissions is a difficult task, partly due to the reactive nature of NH3 within and surrounding the feedlot. Our study used a dispersion model coupled to field measurements to derive NH3 emissions from a feedlot in southern Alberta, Canada. The average feedlot NH3 emission was 50 μg m−2 s−1 (85 g animal−1 d−1), which coincides with a low dietary crude protein content. At a location 165 m east of the feedlot, a flux gradient (FG) technique measured an average NH3 deposition of 12.0 μg m−2 s−1 (west wind) and 5.3 μg m−2 s−1 (east wind). Ammonia FG emission averaged 1 μg m−2 s−1 with east winds, whereas no NH3 emission was found for west wind. Using soil‐captured NH3, there was a decrease in deposition with distance from the feedlot (50% over 200 m). Collectively, the results of this study provide insight into the dynamics of NH3 in the agricultural landscape and illustrate the need for NH3 mitigation to improve the environmental and economic sustainability of cattle feedlots.

Core Ideas

Beef feedlots are “hot spots” of ammonia emissions in the landscape.

A significant fraction of the emitted ammonia is deposited to local land.

Nitrogen fate of emitted ammonia is dynamic.