bluuebunny/crossref_metadata_2025 huggingface dataset:
Synthesis and Biological Effectiveness of Some new Azo Compounds as Derivatives of Nitrogen Bases
Authors: Zaidan Noor Khalid , Mohamed Wissam Mahmud
Published: June 2016

In this study the new azo compounds (3compounds) for nitrogen bases (Adenine and Cytosine) are synthesized through two reaction steps (formation of diazonium salt and coupling reaction). The compounds have been characterized by FTIR, melting point, and ultra-violate (UV) spectra. All synthesized compounds have been estimated in vitro for their antimicrobial activities against two species of bacteria(E.coli, S.aureus)and one kind of fungi ( Aspergillus flavus) .The results show that these compounds have very good antibacterial and antifungal activities especially compounds 1 and 3.To study the effect of these compounds were making some physiological tests on rats are made ,the results of hematological study showed decreasing level of total hemoglobin concentration in all treatment groups specially in group (1).The values of Packed in cell volume (P.C.V) are within normal blood range of rats . Total leucocytes count (W.B.C) decrease in all groups.
Measurement of radionuclides in imported Coffee Consumed in Basra southern of Iraq and estimation of its annual effective dose
Authors: Abbas Ali Abd , Ibrahim Abdul-Munem Khaleel , Kadhim Marwah Jawad
Published: June 2016

Radioactive elements were identified in samples of imported coffee consumed in the province of Basra using gamma spectrometry SAM940TM. It is a scintillation detector of NaI(Tl) crystal and the dimensions of 2×2 inch. We have identified specific concentration As(Bq/kg) and annual effective dose D(Sv/y) for radioactive elements (_^40)K, (_^131)I, (_^134)Cs and (_^137)Cs. The estimated average effective dose for adults from coffee samples were found to be 0.037mSv/y, 88.434nSv/y, 46.909nSv/y, 27.212nSv/y for ((_^40)K,(_^131)I,(_^134)Cs,(_^137)Cs) respectively. The present results of the study revealed that the radioactivity was relatively low in the coffee and within the permissiblelimit.
Second Semilog Pressure Derivative in Pressure Transient Analysis of Gas-Condensate Wells with Strong Phase Redistribution: Field Case Study
Authors: Adrian P. M. , Moreno R. B.
Published: June 2016

Well testing data is usually affected by different wellbore effects. Phase redistribution is one of the most important in gas wells with high liquid production (condensate or water) and volatile oil wells. The longer the wellbore phenomena, the higher the probability to distort reservoir pressure behavior (infinite acting flow regime, linear flow, etc.).

In this situation, the conventional pressure transient analysis would be hard to perform, increasing the probability to obtain erroneous values of permeability and skin factor. Nevertheless, in the last years, the use of primary and secondary pressure derivative as a diagnostic plots (Semilog and Log-Log plots), demonstrated to be very useful in low permeability gas wells and weak phase redistribution gas wells.

This paper evaluates of the second semilog pressure derivative technique for different types of phase redistribution. It also presents the application of this diagnostic plot in the interpretation of two gas-condensate well test with strong phase redistribution phenomena. Results highlight the applicability of second semilog pressure derivative over other similar techniques.
Managing Well Interventions during Low Oil Prices
Authors: Nkeisha Francis
Published: June 2016

During the last quarter of 2014, WTI crude oil price dropped precipitously from an average US$75 to a startling US$42. Production targets were difficult to achieve as the economic margin for well interventions narrowed. The revised objective was increasing oil production while minimizing investment cost and ensuring profitability of the well interventions. Identification of quick-win initiatives which required minimal investment to reactivate wells or increase their production included rig less interventions such as coiled tubing clean out campaigns and coiled tubing gas lift. Candidates which required heavy workovers were assessed through the RAPID process: R(eview) A(ssess) P(lan) I(mplement) D(iscuss). This process, though a part of our daily operations, was not aggressively implemented as oil prices further declined but was applied to the well review process to allow Petrotrin to be better prepared for more favourable oil prices. A revision to the economic feasibility of all well interventions was also re-evaluated to more lenient parameters. The estimated production from the quick-win initiatives was 500 bopd (unrisked) with a risked gain of (375bopd), whilst the estimated production increase from the application of the RAPID technique is expected the realize 1800 bopd (unrisked) with a risked production of 1080bopd. Well testing though significant, remained a challenge for proper evaluation of both the quick-wins and heavy workovers. In its absence Tubing Head Pressure (THP) and Line Pressure (LP) were monitored along with total transfer volumes at metering points to ensure expected gains were as was modelled. The economics of these projects were evaluated ensuring a Discounted Cash Flow Rate of Return (DCFROR) greater than 25%. Wells which did not meet the economic hurdle rate after the application of the RAPID technique were omitted pending more favourable oil prices, for cost optimization, Petrotrin proposes to implement the RAPID technique by project basis for operations such as fishing and well control for high pressure (HP) wells. Upon its approval, it would be included in the company's Standard Operating Procedure.
Application of Markov Chain Monte Carlo Proxy Modelling Based Workflow to Demonstrate Robust Convergence of In-place & Recoverable Volumes
Authors: Singh Sidharth , Zimmer Colin , Jamankulov Arman , Martinez Alejandro
Published: June 2016

A dry gas reservoir offshore North Trinidad has been on production since 2002 with a high recovery to date. Notwithstanding this maturity, significant volumetric uncertainty was suspected and this had the potential to alter the field development plan. Hence, a robust quantification of hydrocarbon volumes was deemed necessary through a study that rigorously captured risks and uncertainties and provided higher confidence in the predicted remaining reserves.

Experimental design based uncertainty analysis, Markov Chain Monte Carlo for Bayesian optimization and proxy modelling assisted history matching methodologies were used. Scoping Latin Hypercube (LHC) simulations were run to test a wide range of volumetric scenarios. MCMC allowed Bayesian optimization to be done in an unbiased manner but being computationally expensive, a proxy modelling workflow was utilized. Top LHC cases were selected to train a proxy. The efficiency of the proxy workflow enabled hundreds of full field proxy simulations to be run in a short time. All experiments were combined and an optimum filtering criterion established to short list potentially matched cases. Finally, stochastic volumes were selected from this filtered pool.

Due to the use of Bayesian algorithm, posterior uncertainty distributions were often different, and thus quite insightful, when compared to the prior distributions. The shape of prior distributions had limited impact on the final result. A limited number of LHC runs scoping a wide sample space were sufficient to train a robust proxy model. Acceptable history matches for all wells could be achieved just after the second MCMC cycle. LHC workflow allowed wider uncertainty sampling but typically poor matches, whereas MCMC proved to be a rapid & highly effective history matching technique but it tended to smooth out extremes volumetric results and converged towards a high confidence median. A key result was the observation of a very strong correlation between the "global" history matching error and field gas-in-place or recoverable volumes.

Use of this Proxy based workflow allowed significant reduction in computational costs. A powerful cross-plot analysis methodology is presented that demonstrates convergence of hydrocarbon volumes to a narrow range. Results showed that irrespective of the deterministic starting inputs, reduction in history match error was only achieved for a narrow posterior range of uncertainties and volumes, even where a large initial uncertainty was believed to exist. These results were successful in achieving the objective by largely reducing the volumetric uncertainty and re-confirming the initial view.
Trinidad and Tobago's Current Deepwater Campaign: Implications of the Contractual Obligations and Taxation Regime
Authors: Razack J.
Published: June 2016

Trinidad and Tobago is exploring 9 frontier blocks in water depths 1800 to 2200m. 3D seismic was completed in 2015 and the first well is to be spudded by mid-2016. As per the contracts, a minimum of 8 exploration wells are to be drilled. This paper aims to determine how small an oil or gas field could be and still generate economic rent.

The taxation system and contractual obligations for two blocks were used to model oil fields of reserves 150 and 300 mmbbl and gas fields of reserves 2400 and 4800 Bcf. The production rates and oil/gas prices were varied to determine their impacts on investment criteria like NPV, IRR, payback time and government take. The models were used to project the minimum field sizes at different oil and gas prices that would be commercial.

At $60/bbl, the minimum economic size for a standalone oil field is approximately 300 mmbbl reserves. Economic means that the field must attain a positive after tax NPV @10%. None of the gas models were economic at $3/mcf. It was projected that at this price, a single field with at least 12 Tcf reserves must be discovered to be commercially viable.

Further, the minimum obligatory spend on the 9 blocks is approximately $765M in 2012 dollars. To breakeven with this expenditure, (that is, post-tax NPV = $765M) the largest field modelled (300 mmbbl) requires an oil price of $100/bbl.

First tax revenues are forecasted as 2026 for oil and 2029 for gas. The first PSCs were executed in 2012, so first production is modelled 14 to 17 years later. Government take ranges 55 – 60%. While the PSC mechanism of taking taxes out of the government’s share reflects long term stability from the investor’s point of view, changing individual tax rates may be irrelevant as the full taxes owed are never paid over the field life.

These models are dependent on a myriad of assumptions. Variations in reservoir characteristics, new technology, market availability and global prices can have dramatic effects on the results.

The deepwater is widely considered to be the last frontier for T&T’s hydrocarbon industry. Therefore, it is critical that we understand how the contracts and taxation regime affect the commerciality of any potential fields, and make any necessary changes.
Mature Field Rejuvenation by Reactivation of Idle wells in Petrotrin's Land Acreage
Authors: Batohie G.
Published: June 2016

In 2011 January, the Petroleum Company of Trinidad and Tobago (Petrotrin) embarked on an initiative to rejuvenate its mature land fields by using different intervention strategies to monetize the remaining reserves in its inventory of idle wells. This exercise included but was not limited to annexation of idle wells to Lease Operators and a reactivation exercise seeking to generate oil production from a total of one thousand, seven hundred and twenty six (1726) inactive wells, which included three hundred (300) inactive wells that were in close proximity to the active lease operatorship blocks and were earmarked for lease out. This paper presents results from the reactivation exercise.

The candidates reviewed for reactivation were in mostly shallow, unconsolidated reservoirs, onshore Trinidad. Most of Trinidad's onshore crude oil producing reservoirs is considered to be mature which means that the oil reserves would have been, or are still being, produced by primary means, with Enhanced Oil Recovery (EOR) methods being used in some reservoirs. With declining oil production being experienced currently, there is the need to find alternative ways of arresting the declining production trend. One method of doing this is by tapping into the proven, idle reserves from wells that may have been taken off production due to low production rates and unfavorable economics at the time. Identification and reactivation of candidates is therefore important in helping to realize the full potential of mature producing fields such as those onshore Trinidad and to recover potentially bypassed pay. The reactivation project applies current technologies for identifying and unlocking potential in inactive wells.

A total of one thousand and seven hundred (1700) wells were screened as candidates for the Land Reactivation Project as at September, 2014. This paper reports on the performance of the wells reactivated for the period of January, 2011 to September, 2014, a period of approximately four fiscal years. This phase of review and evaluation was termed Phase Four (4) of the Reactivation Project and it forms the basis of this paper.

The total number of wells reactivated during this period was two hundred and seventy six (276), with a total of one hundred and ninety two (192) wells maintaining active status and eighty four (84) wells inactive at September, 2014. This equates to an overall project success rate of seventy percent (70%). Approximately fourteen million dollars ($TT 14million) profit, for fiscal year 2013-2014 was realized. These results prove that reactivations are an economically attractive venture.

Due to fallen oil prices at this time, exploration and production of new reserves to boost declining oil production may not be economically attractive and reactivation of idle wells may prove to be a more feasible option in some instances.
Application of a Steam Assisted Gravity Drainage Model to Deviated Wells in a Dipping Heavy Oil Reservoir
Authors: Ramasray K. , Sobers L. E.
Published: June 2016

Objectives/Scope

The Butler Analytical model has been used to predict steam flood performance using Steam Assisted Gravity Drainage (SAGD). In this paper we apply the Butler Analytical model to three pairs of deviated wells in a steeply dipping heavy oil reservoir.

Methods, Procedures, Process

Simulation studies were carried out on a 100ft thick heavy oil sand with 12 degree API crude for three pairs of parallel deviated wells in a dipping reservoir, situated perpendicular to the 40 degree incline of the reservoir. The results of the simulations study were compared to the production profile predicted by the Butler Analytical Model.

Results, Observations, Conclusions

Both the simulation results and the Butler Analytical Model predict a production profile with two production peaks. The results of the three pairs of parallel deviated wells show the effect of dip and well placement on oil recovery (average 53%) and water production. The major factors influencing the formation of the steam chamber and oil production are reservoir heterogeneity, steam override and well placement. Overall, cumulative production values obtained from the Butler analytical model were less than those from the simulation but the production profiles were comparable. The main difference is due to the advantage of optimal well placement which the Butler analytical model does not take into account. Our results show that the downdip positioning of wells increased oil production. The results of this study are then more closely aligned with the findings of Ramjohn (2014) than Andarcia et al (2014), which concluded that SAGD, (modified for dipping reservoirs), can be effective with optimal well positioning.

Novel/Additive Information

The work presented in this study shows that the Butler Model can be used to predict steamflood performance in deviated wells to recover heavy oil from dipping reservoirs.
Offshore Economic Field Development Concept - Step Change
Authors: Prescott C. N. , Paramsook S. , Mohammed W. , Mejia F.
Published: June 2016

Oil prices have fallen dramatically to the average range of USD $30 to $50 per barrel and are expected to stay in this average range through 2017 or beyond. Field development costs for deepwater have fallen but are still a major obstacle to efficient field development and this is not expected to change in the foreseeable future. A failure to adapt to this new economic reality could seriously impact the industry. New strategies and concepts are needed to ensure a sustainable deepwater industry, especially for the more challenging reserves. This presentation will discuss a step change solution to providing a field development concept that will be economic in today's conditions.

New strategies and concepts for deepwater field development will be discussed for a cost-challenged environment. Partnering and development strategies will be defined, as these will facilitate subsea development of the most challenged assets and could reduce project cost by up to 30% and to shorten project schedule by 18 months to 2 years.

This paper will discuss the following: Development strategies to go forward for a cost-challenged deepwater businessNew development concepts for field development, including processes and equipment beyond Jules Verne conceptNew partnership models to allow for economic provision of resources: utilities, water, etc.Standardization recommendations.

Major changes are needed to empower the move to an economic field development concept and these will be discussed with details showing the future of deepwater development.
Quantification of Simulation Model Grid Size Impact on Polymer Flooding Application in Heavy Oil Heterogeneous Reservoir
Authors: Rego F. B. , Botechia V. E. , Correia M. G. , Schiozer D. J.
Published: June 2016

Polymer flooding can be a viable alternative to enhance oil recovery of heavy oil fields. The comparison of water and polymer flooding requires a reliable reservoir numerical model to safely ensure the decision analysis including uncertainties and involving a significant amount of simulation runs. Reservoir engineers usually work-around this problem using fast models to reduce computational time; however, it is important to maintain the reliability of heterogeneous reservoir models. Therefore, the proposed work demonstrates how the grid size impacts on accuracy of results and both the time and computational resources. In addition, it is performed an analysis to establish how the typical physical phenomena related to the polymer flooding impact the applicability of the proposed methodology.

A highly heterogeneous heavy oil field is used in our proposed studies. The application is conducted to assist pilot test wells. Initially, the definition of the reference strategy (OTM) is presented. In this case study, the OTM strategy is based on the optimization of location and number of wells. Secondly, the effect of grid size on the process is evaluated through two procedures: (1) DA method: a selection of grid size defined by drainage area of the selected wells; and (2) UP method: upscaling is performed in the simulation model. Then, production parameters resulting from models of both procedures (DA and UP) are compared with OTM results. The definition of which procedure is better to represent the wells of interest is performed. Finally, the impact of three polymer flooding physical phenomena (degradation, adsorption and Non-Newtonian effect) on production results is presented, in order to verify the accuracy of the generated fast models in maintained considering these effects.

The DA method present good accuracy for reservoir response compared to the reference OTM results. Differently, UP models are not as accurate as DA models for production results indicators. In conclusion, the application of the methodology allows choosing the DA over the UP technique to support our decision in the investigated recovery methods, showing a reliable and fast procedure. Finally, this procedure shows excellent applicability and robustness when a typical polymer flooding study is carried out: the evaluation of physical phenomena impact on production results based on wells of interest.
The Experience of Using Jet Pumps with Hydraulic Pumping Bottom-Hole Assemblies to Reactivate Idle Wells in a Heavy Oil Reservoir in the East Soldado Field
Authors: Mohammed Shazim K.
Published: June 2016

This paper presents the performance and compatibility of using jet pumps with hydraulic pumping bottom-hole assemblies that were designed to work with hydraulic piston pumps in an attempt to reactivate idle wells in a heavy oil reservoir, offshore South-West Trinidad. The resilience of the already installed hydraulic bottom-hole assemblies made it easier to select jet pump as the artificial lift method for reactivation.

Jet pumps were designed with dimensions to fit in the hydraulic bottom-hole assemblies. Assemblies were modified by using a 13 ft length of 2" pipe inside them to ensure that the seals in the pumps and the polished sections of the assemblies meet at the same depth. The production string from the triple string completion was isolated since only 2 completion strings were required for operation, leaving the power oil injection and fluid return strings active. Jet pumps were installed on 4 wells. Performance was monitored using sonologs to determine fluid levels and clamp-on ultrasonic flowmeters to determine injection and production rates.

Results showed that drawdown was occurring and production was obtained from all 4 wells during the first 4 months of operation since submergences were lower than the static levels. After this period, the submergences of 3 wells increased to the static levels and test rates showed that these wells were not producing. The submergence of the 4th well was fluctuating and tested 76 bpd. On inspection, it was discovered that the throats and nozzles of the other 3 wells were plugged with seal fragments from the surface power oil pumps. The jet pumps were cleaned and reinstalled after which the submergences dropped drastically within the first month of returning to operation. From these results, it can be concluded that the jet pumps are compatible with the modified hydraulic pumping bottom-hole assemblies. All 4 idle wells completed in this heavy oil reservoir were successfully reactivated however the performance was affected by plugged nozzles and throats of the jet pumps by seal fragments from the surface power oil pumps. Submergences could be reduced to optimize all 4 wells by changing the nozzle and throat sizes to achieve optimum performance and production rates with the maximum power oil injection pressure of 2400 psi.

This paper describes the experience of using jet pumps in the East Soldado field to reactivate heavy oil wells by making minor modifications to the existing hydraulic bottom-hole completion that was designed to be used with hydraulic piston pumps. The use of jet pumps was motivated by the need to reduce workover and operating costs together with the demand to increase oil production. This modification was successful based on the production and monitoring parameters obtained.
Experience with Progressive Cavity Pumps in the Soldado Field, Offshore Trinidad
Authors: Garcia-James C. J.
Published: June 2016

The use of progressive cavity pumps (PCP) in the offshore assets (Soldado Field) of the Petroleum Company of Trinidad and Tobago Limited (Petrotrin) began with pilot projects in early 2000, however full adoption of this artificial lift system occurred from 2003-2005. Almost a decade after and due to a reduction of run life of the pumps and the increase in workover frequency, a complete review of the PCP system was done in order to identify type and causes of failures, present best practice solutions to reduce premature failures and recommendations for optimum design and operation. This paper discusses the results of the review and the steps being implemented by Petrotrin Trinmar Operations towards the management of PCP during the productive life of an oilfield.

The initial approach was the visit of Subject Matter Experts (SME) to Petrotrin Trinmar Operations to consult with production engineers and field operators on the problems experienced. Detailed evaluations were performed on the type of failures and their location in the PCP system. Destructive and non-destructive test were done on selected rods, pumps and accessories. Supervision during the running of sucker rods into producing wells to ensure the proper installation of the systems. Revision of the processes and participants in the management of Artificial Lift Systems (ALS) i.e. identification of candidates wells for PCP, design and procurement of these systems, installation and pulling, monitoring and maintenance. The process was completed with the establishment of Key Performance Indicators (KPI) to assist in decision making regarding the performance of PCP.

The results indicated that the run lives of most PCP systems in Petrotrin Trinmar Operations were similar and sometimes above the average of systems installed in North America. The common failures were categorized as mechanical due to wear and tear during operations, lack of maintenance and improper design. Some of the reasons for early failure were attributed to improper manufacturing and installation of new systems. Delegation to the suppliers of the design, selection and installation of PCP was a good approach during the learning curve of operators (Petrotrin Trinmar Personnel), however as the systems were fully adopted by the company, appropriate training and development of a culture associated to the use of PCP needed to be developed since these classic systems can turn into new technologies due to their scarce use.

PCP Management should be taken as an integrated vision in accordance with the development of the Soldado field due to the need to maximize production and the high economic impact that the products and services associated to PCP have on lifting costs.
Drilling Optimization Platform for Well Cost Optimization
Authors: Sawh Viveka , Solomon Herlene
Published: June 2016

As operators strive to become more efficient on cost and performance during well construction, their approach to tracking invisible lost time (ILT) and non-productive time (NPT) has been revamped. A state-of-the-art software platform has been introduced into the market to monitor and optimise drilling performance in real-time, enabling early detection of ILT and NPT events, ultimately saving rig time and reducing associated costs.

Given the current economic climate, this platform allows for a smart approach to reduce inefficiencies when drilling a well by its innovative approach of benchmarking and monitoring. One of the competitive advantages of utilising this platform for a drilling advisory service is the pre-job study, in conjunction with the operator, to develop the key performance indicators (KPI) that will be referenced as benchmarks for real-time trend monitoring.

Up to 39 different KPI's, such as rate of penetration, on and off-bottom time, circulating and connection times are determined, however for this study, the performance indicator of connection times while drilling and tripping will be analyzed. With a more user-friendly interface, optimized for 24/7 trend monitoring, this platform serves to be a more beneficial and market-leading approach to performance monitoring.

The aforementioned, coupled with breakthrough thinking, reveals the potential for savings which can be harvested by the operator by driving operational performance, resulting in more proficient operations. This paper will showcase one such case history to reveal missed opportunities and the associated cost and value benefits.
New Challenges in Construction and Production Prediction Using Multilateral Well to Develop Ecuadorian Oilfield in Environmental Sensitive Areas
Authors: Bone Romel Erazo , Aguilar Fidel Chuchuca , Segovia Kenny Escobar
Published: June 2016

Design the multilateral well trajectory in vertical section, like to dual lateral and fishbone wellbore, for drainage M-1 and M-2 reservoir and perform a numerical reservoir simulation to predict the behavior of production for each of the types of multilateral wells.

The use of different configuration of Multilateral well technology would help to increase the drainage reservoir area and the oil production form singular well path, also reduce the amount of drilling well for the development oil field, leads directly to the reduction of spatial area required for well-path, which is very beneficial for the environment because it let to decrease the impacts and footprint on the oilfield area, also the use of ML technology helps reduce costs directly related with drilling wells.

This study had been divided in two stage to have a better performance. Therefore the first stage is designing a multilateral well trajectory and the second stage is determine the performance of productivity using multilateral well (dual lateral-fishbone)

Nowadays the environmental sensitive areas it's a very concern factor to considerer into the design and development oil and gas project, especially when there are a lot of oil reserve proved into this area, therefore during the design phase of the oil project is very important considering the footprint into the oilfield.

Also in this work we studied the technical and economical applicability of multilaterall wells in reservoirs with the properties and characteristics of Ecuadorian reservoirs in environmentally sensitive areas, where the theoretical reservoirs were simulated at different scenarios varying values of vertical permeability, length of open zone. Also we built an economical model, using Microsoft Office Excel 2007, for the economical analysis, tacking care account of the cost of all the taxes fixed by the State.
Efficient Development Method for High-Viscosity, Complex Fault-Block Reservoir
Authors: Xu Shiqian , Feng Qihong , Guo Fajun , Yan Aihua , Liu Shumin , Tao Yayuan , Chen Xiaoqin
Published: June 2016

XXX unit of Huabei oilfield, a complex fault-block and high viscosity reservoir, has stepped into middle period of development. Though the water cut has reached 81%, only 4.7% of the original oil in place (OOIP) has been produced, indicating that the current development method for this block may be inappropriate.

In order to improve the production performance of this block, we studied the proper development technique on the basis of its geologic features. We examined the applicability of combining individual layers, and determined the upper limit for the segments of an injector as well as the optimal injection rate for each segment. In addition, we estimated the reasonable well density, the oil production rate, the injection-production ratio, and formation pressure using both numerical simulation and reservoir engineering method.

We further coupled reservoir simulation with an optimization algorithm to provide proper measures for the improvement of oil recovery. The first measure examined is to divide layering segments and complete the well pattern. Our simulations give the optimized position of new wells. The primary oil recovery of two layering segments increases by 2.33% and 1.75%, respectively. The second one is the optimization of liquid production rate. In comparison with the current development state, the optimized schedule will increase the primary oil recovery of the two segments by 2.1% and 1.2%. Therefore, the optimized technique may serve as an effective approach to develop other fault-block reservoirs.

In this work, several development methods demonstrate a significant effect to enhance oil recovery for complex fault-block reservoir, which can give a good guidance for other similar reservoirs.
Channeling Identification: A Routine Surveillance Exercise for Successful Waterflooding Management in Casabe Alliance
Authors: Mora G. , Bonfanti B. , Porlles J. , Casas J. , Agudelo O.
Published: June 2016

The sedimentary environment in Casabe field is a complex continental-fluvial deposit conformed by numerous stacked sandstone reservoirs intercalated with shales with high lateral and vertical heterogeneity. In that conditions Casabe has been under Waterflooding for 30 years with successful results due to an efficient vertical and areal sweep achieved through selective injection.

The successful in production increment also bring us a huge increment in produced water in a ratio of 1 BOPD to 6 BWPD. But, we notice that there where patterns with more than 90% of BSW in between of patterns below than 70% of BSW. Considering additional arguments evidence lead us to rethink our vertical distribution.

With the water channeling identification in mind our reservoir surveillance process was adjust going further in layer by layer analysis from the production-injection balance and the pore volume displaced to get an indicator of where water is going in order to come with a general or localized solution. All the analysis required gather and integrate information from tools like inter well tracers, PLTs, swabbing by layers, saturation logs, time lapse resistivity logs, and cement logs where there was an opportunity to run the tools.

After the identification of water recirculation (Bad Water) in zones with high permeability the immediate action to stop water recirculation and reduce produced water was blocking zones in 1) Producers: Water shut off and/or 2) Injectors.

In the long term, a more comprehensive solution for water channeling will be Water Conformance as the saturation logs shows there is still oil in those layers.

The results of the work done in 21 production wells was the reduction of produced water up to 300 BWPD per well achieving water cuts lower than 80%. Additionally and more important was the increment in oil production observed in the same wells as a consequence of vertical swept efficiency improved.
Proppant Management: A New Challenge to Develop Unconventional Reservoirs in Argentina
Authors: Bonapace J. C.
Published: June 2016

Hydraulic fracturing has become a critical component in the successful development of unconventional reservoirs; it is well known that constructing an economic well in this type of formation is very challenging. In the last 15 years, exploration and development of unconventional reservoirs (tight gas) has been initiated. Over the past 5 years, the main target in Argentina has been located in the Vaca Muerta shale, which is one of the main source rocks in Argentina. Such a development challenge requires one to develop a fast learning curve to more quickly achieve economic wells. This type of completion and stimulation involves vast amounts of water, proppant, chemicals, and special equipment, coupled with continuous improvements in operations, quality, cost, time, and safety. Various alternatives in proppant management were explored and introduced. This paper describes several aspects related to stimulation of different tight formations and shales in Argentina, including proppant selection, supply chain, logistics, new storage systems, and laboratory studies performed on local white sand. The focus will be on these key aspects: Stimulation: information about proppant type, amount, and size for hydraulic fracturing performed in several tight and shale formations in Argentina with more details of the Vaca Muerta formation.Logistics and supply chain: improvements introduced from transportation, storage, and handling of proppant, including the evolution process over the last few years, from centralized storage sites to the wellsite.Laboratory: several samples of white sand procured from different parts of Argentina were evaluated to be used in hydraulic fracturing. API and ISO standards were used for qualifying tests including specific gravity (SG), bulk density, acid solubility, turbidity, sphericity, roundness, sieve analysis, and crush strength.
A Comprehensive Model for Performance Forecast of Multiple Fractured Horizontal Well in Unconventional Reservoirs: A Case Study
Authors: Chen Z. M. , Liao X. W. , Zhao X. L. , Liu H. M. , Tian J. , Zhu L. T. , Wang L. , Zhao H. J.
Published: June 2016

Performance forecast of multiple fractured horizontal well (MFHW) becomes a hotspot in the development of shale gas (SG) reservoirs. Due to geological and engineering factors, there exists complex mechanisms including stress-sensitivity effect, diffusion flow, gas desorption, finite fracture conductivity, and wellbore hydraulics. However, little work has been done to focus on these complex mechanisms simultaneously.

To comprehensively study this issue, a more comprehensive model was proposed in this paper. In this model, some aspects were all considered: (1) flow mechanisms of viscous flow, slip flow, transition flow, and Knudsen flow, (2) gas desorption and diffusion flow, (3) stress-sensitivity effect of permeability, and (4) wellbore hydraulics in the horizontal wellbore. The first part of this paper was model development and solution. During this process, model was developed based on the flow mechanisms of SG and its solution was obtained by applying a semi-analytical method. The second part involves model validation and case study. To verify the model, the results from the proposed model were compared with those from a commercial software, KAPPA Ecrin. After model validation, based on a real case from the Sichuan Basin, type-curve matching and parameter estimations were conducted using the proposed model.

This study further narrows the gap between theory and practice of performance predictions for MFHW in SG reservoirs.
Evaluation and Optimization of Oil Wells on Plunger Lift in the Main Soldado Field Offshore the Southwest Coast of Trinidad
Authors: Mohammed S. K. , Hosein R.
Published: June 2016

Plunger lift is a well-known artificial lift technique originally developed for the de-liquefaction of gas wells. However its use has been extended to include high Gas – Oil Ratio (GOR) oil wells, those with low or no production due to paraffin and scale deposits and wells with high or fluctuating sales line pressures. It is an intermittent production technique that utilizes reservoir energy stored in the gas phase to lift oil from the bottom of the well to surface via the vertical cyclic action of a "pigging" device within the tubing. This action enhances the production performance of liquid loaded wells.

In this study, plunger lift systems on two wells were evaluated to determine well performance and to optimize production rates if plunger lift systems were to be installed on other wells. Casing and tubing pressure trends were used to identify operational deficiencies and causes. Vogel's model was used to model the inflow performance relationship using bottom-hole pressure data. The Foss and Gaul model for plunger lift operation was used to determine production rates and gas requirement for each well in order to optimize well performance. The mode of operation with the current settings (long after-flow periods and over-estimation of plunger fall back time) is representative of intermittent lift with the assistance of a plunger rather than gas assisted plunger lift operation. The GOR for both wells are too low for efficient operation and a model of the current settings indicates that a gas injection rate of 450 MSCF/D is required to obtain an optimum oil production rate of 103 bopd. These plunger lift systems also prevent paraffin accumulations in the production tubing of these two wells.

New plunger lift operating variables such as casing valve opening and closing time, gas injection rate, after flow time, plunger rise velocity and fallback time, flow-line motor valve cycle time and number of cycles per day were modeled to obtain an optimum oil production rate. The results showed that a gas injection rate of 173 MSCF/D is required to obtain an oil production rate of 195 BOPD for a plunger rise velocity between 800 to 1000 ft/min. For these new settings the gas requirement was reduced by 61 % and the oil production increased by 89 %. These results indicate that the modification of the operating variables can effectively optimize gas assisted plunger lift systems that are installed in the oil wells producing from the Cruse Formation in the Main Soldado field offshore the Southwest coast of Trinidad.
Effective Flare and Vent Management
Authors: Siu J. , Perseval A.
Published: June 2016

As the world reacts to a low commodity and oil price markets, energy companies are forced to seek more efficient ways of operating. This paper addresses the impacts of improperly managed gas disposal systems including lost revenue potential as well as the contribution to greenhouse gas emissions. It is tailored to the energy industry of Trinidad and Tobago which aims to achieve a reduction in overall emissions by 15% by 2030 from BAU (Business As Usual baseline) under the UN Framework Convention on Climate Change.

The study highlights and evaluates the major opportunities for emissions reduction including, but not limited to, conversion from cold vents to flares, implementation of hybrid flare-vent systems, conversion from natural gas to inert gas purge systems and proper monitoring and optimization of flaring rates. Supporting calculations and case studies are based on actual and theoretical data (from mass balances or otherwise) from local oil and gas operators.

The lack of reliable measurement data and trends for flare volumes was indicative of an industry that has grown callous to wastefulness. Findings revealed that significant value can be extracted through modest monitoring improvement projects, optimization of existing operations and increased operator conscientiousness.
A Model-Based Production Strategy Selection Considering Polymer Flooding in Heavy Oil Field Development
Authors: Botechia V. E. , Correia M. G. , Schiozer D. J.
Published: June 2016

Polymer flooding is a chemical EOR technique in which polymer is added to injection water, increasing its viscosity, decreasing water-oil mobility ratio and hence improving sweep efficiency. This recovery method create unique conditions that are absent in traditional water flooding, which makes an adequate production strategy essential to the success of the project. This work is part of a complete decision analysis process with polymer flooding and the objective here is to present a methodology for production strategy selection considering water and polymer flooding as recovery mechanism options in heavy oil reservoir, guiding the decision maker to have an accurate tool to compare water and polymer flooding strategies and decide which one is the best option in determined project, using numerical simulation and economic analysis. The methodology is divided in seven steps based on variable hierarchy. The optimization process aims the maximization of NPV and the variables optimized are: number and location of wells, production systems capabilities, schedule of well drilling, production and injection rates, economic water cut limit for well shutdown, polymer concentration and slug size. The application of the methodology is made in a model that represents an offshore heavy oil Brazilian field. For comparison purposes, the methodology is also applied considering water flooding as recovery mechanism. The results show the feasibility in applying polymer flooding in early heavy oil field development with better economic return than water flooding. Moreover, this work shows the importance of applying the process separately for water and polymer flooding, otherwise wrong decisions can be made if simple comparisons are performed.
Comprehensive Approach of Reservoir Characterization has Allowed Successful Stimulation of Sandstone Formations in Bachaquero Field-Lake Maracaibo, Venezuela
Authors: Schmid Werner , Martin Alberto , Palacios Jinna Marcela
Published: June 2016

Oil exploitation in the Bachaquero field in east Maracaibo Lake has been occurring for more than 50 years. Sandstone is the primary formation type, and nonconsolidated and poorly consolidated sands are common in this field. Complex mineralogy and fines migration have become root causes of production decline and formation damage. This paper describes a comprehensive approach to reservoir characterization that has contributed to the successful stimulation of the sandstone formations in the field.

Chemical stimulation, specifically matrix acidizing with hydrofluoric (HF) acid systems that are customized and tailored to reservoir characteristics, has proven to be effective at enhancing production in this field. The types of clays that are present include kaolinite, illite, smectite, chlorite, and mixed-layer clays; feldspars are also present. An adequate analysis of each well helps to ensure that HF acid dissolves the clays to restore permeability without promoting nonsoluble fluorosilicates precipitation through reactions with aluminosilicates. Variations in mineralogy determine fluid performance and make customized fluid selection necessary. The high presence of feldspars requires more conservative treatments to avoid undesirable precipitations.

Reservoir characterization and fluid tailoring has helped ensure treatment success, but other good practices also have been applied to help achieve production goals. The stimulation treatment design includes pumping formation-conditioning fluids before and after the main acid; using different types of organic solvents to dissolve asphaltene deposits in the well; performing near-wellbore (NWB), hydrochloric (HCl) acid, and HCl/organic acid blend preflushes and post-flushes to treat calcium carbonate and control the pH and iron precipitation in the reservoir; achieving short-term clay inhibition and long-term clay stabilization; and using other fluids, such as relative permeability modifiers (RPMs) for water-control applications and diversion of treatment in laminar reservoirs with petrophysical heterogeneities. All of these combined practices have resulted in successful stimulation of the field.

This paper discusses in detail this comprehensive approach to reservoir characterization applied successfully in wells in the Bachaquero field. The workflow includes candidate analysis, from reservoir description and mineralogy and formation damage mechanism identification to stimulation treatment design, laboratory fluid systems tailoring, placement and diversion techniques, pretreatment operational task fulfillment, field execution, quality control, and post-job evaluation through analysis of records and statistics.
Comparison of Primary, Secondary and Tertiary Polymer Flood in Heavy Oil - Field Results
Authors: Delamaide Eric
Published: June 2016

Polymer flooding is an Enhanced Oil Recovery process usually employed in tertiary mode, after a waterflood. However, in heavy oil reservoirs the process is also commonly employed either in primary or secondary conditions because waterflooding is not considered to be economic. For new projects the question often arises as to whether it is better to start by injecting water or to go straight to polymer injection. Injecting water first provides a baseline for comparison with the polymer flood and in some cases allows an earlier start-up of the project due to the construction and commissioning of polymer mixing facilities. On the other hand, the risk is that water channeling could occur and could be irreversible, thus reducing the potential recovery during polymer injection.

Some authors have reported laboratory studies comparing the different methods but so far there has been no field results published that could be used for validation or guidance. Although several polymer flood projects in heavy oil have been reported in the past few years they are still relatively few and no detailed field results have been reported to date on that issue.

The largest polymer flood in heavy oil is currently being implemented in the Pelican Lake field in Canada, with several hundreds of horizontal wells injecting polymer. All the methods - primary, secondary and tertiary - have been tested and as a result the field provides a large database that allows to compare recovery and other parameters for each method.

Although such a comparison is mostly focused on a single field and is thus inherently biased, it should provide useful guidelines for companies looking to start new pilots or field projects. Relevant literature on this topic will also be reviewed to present a complete review of the issue.