bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reserves Management System - Rapid Tool for Optimizing and Tracking the Growth of Hydrocarbon Resources & Reserves
Authors: AlBahar Mohammad , Kamal Dawood , AlMayyan Haya , Bora Anup 
Published: September 2011

Abstract
Kuwait’s resources and reserves to date are characterized by giant, large, massive oil and gas fields located in onshore and offshore areas of Kuwait. These fields are under different stages of development like natural depletion, pressure maintenance and enhance oil recovery (EOR) processes. Over the years, huge amount of resources and reserves data has been accumulated from these fields. This has made Kuwait Oil Company (KOC) to re-evaluate its approaches towards management of these huge volumes of data efficiently. With passage of time, it has become more challenging to manage these reserves and resources volumes and promotions to meet company’s growth strategies.
Historically, KOC was managing its resources and reserves through a manual Reserves Management System (RMS) spreadsheets for tracking, archiving, monitoring, reporting and managing the resources and reserves.With time, RMS has become a very complex and involved process and it was felt necessary to introduce a new process and tool to manage the overall RMS workflow efficiently to meet company’s business needs. Accordingly, KOC decided to introduce a systematic workflow tool to streamline the process of managing hydrocarbon resources and reserves data. The new workflow process consist of a robust multiusers database for archiving, managing and reporting which can be accessed by different teams at different security levels. This enhanced system enabled KOC’s management and reserves evaluators to optimize the company’s resources and identifying possible opportunities to meets its strategic goals.
Effect of Surfactants on Water Imbibition into Heterogeneous Carbonate Rocks at an Elevated Temperature
Authors: Han Ming , Fuseni Alhasan B. , Yousef Ali A. , Kokal Sunil L. , Al-Saleh Salah 
Published: September 2011

Abstract
Spontaneous imbibition of water into water-wet reservoirs has a positive effect on oil displacement and recovery. For carbonate reservoirs which are generally neutral to preferential oil-wet, surfactants may be used to alter wettability towards water-wet that assists water imbibition and consequently oil recovery. Depending on the surfactants selected, oil recovery can be significantly improved for carbonate reservoirs. This paper presents the results from a laboratory study on improved spontaneous imbibition of water into oil saturated carbonate rocks using surfactants. Three kinds of surfactants and one surfactant/polymer formulation were selected and evaluated in terms of compatibility with field brines, critical micelle concentration, interfacial tension, contact angle, and viscosity. The imbibition experiments were performed at 75°C to investigate oil recovery potential and the impact of interfacial tension, wettability, and viscosity. The results show that the addition of the surfactants can significantly oil recovery in the secondary oil recovery mode, compared to the imbibition process of water alone. Similar oil recoveries were observed when surfactant was used alone or mixed with a polymer. In tertiary oil recovery mode, low interfacial tension fluid showed a greater incremental oil recovery. This paper provides insights on selection and utilization of chemicals in increasing oil recovery from carbonate reservoirs, based on imbibition experiments.
Measuring the Performance of Corrosion Inhibitors to Prevent Black Powder Formation Using a Novel Quartz Crystal Microbalance Technique
Authors: Jovancicevic Vladimir , Ramachandran Sunder , Cattanach Kyle , Sherik Abdelmounam 
Published: September 2011

Abstract
Black powder formation is an oxidative corrosion process that over time can cause operational problems as the solids collect within the system. There is a net weight gain within the system as molecular oxygen becomes incorporated as part of the solid materials. A novel quartz crystal microbalance (QCM) test apparatus has been developed to determine the effectiveness of various corrosion inhibitors to prevent black powder formation in sales gas pipelines. The QCM measures minute changes in frequency of a quartz crystal with weight gain/loss. For our test apparatus, the QCM crystal was coated with iron where small increases in mass due to oxidation of the iron layer were recorded as a drop in frequency. Using the Sauerbrey equation, the drop in frequency observed during corrosion testing can be converted to a corrosion rate. Several inhibitor chemistries were tested using the QCM apparatus. In this study it was found that a new oil-soluble corrosion inhibitor is the most effective for preventing black powder formation under the sales gas conditions.
Monobore Expandable Liner Extension Deployment Saves Well From Abandonment
Authors: Stockmeyer Carl F. , Durment Albert S. , Ismail Ahmed , Lapeira Manuel 
Published: September 2011

Abstract
Caving, sloughing, and swelling shale sections, combined with lost returns below 13-3/8-in. casing, were encountered in an Egyptian well. Before the 12.25-in. hole section was completed, shales packed off the drillstring and part of the bottomhole assembly (BHA) was left in the hole. Casing (9-5/8-in.) was run as deep as hole conditions allowed, with a recess shoe to enable a monobore expandable liner extension. Following drillout of the shoe, conditions presented the same challenges previously experienced. The 8-in.outside diamer (OD) liner extension system was run, but well conditions prevented getting the liner to depth and it was pulled out of the hole.
Conditioning trips with increased mud weight up to 12.3 pounds per gallon (ppg), reaming and backreaming, along with an open hole cementing effort, were performed for stabilization. A second attempt was made to run in the hole. The hanger located in the recess shoe profile of the 9-5/8-in. casing and the system was expanded to the same inside diameter as the casing above. The expanded liner’s shoe was now located just above the previously left BHA, but the trouble zone sections were isolated with no reduction in hole size from the previous casing.
The expanded liner was pressure tested to 1,000 psi before cementing. Recess shoe ports were enabled and initial circulation established, and the wellbore did indeed pack off and build pressure, preventing full annular cement. Pressure inside the casing was applied and 15 barrels (bbl) of cement were squeezed into the hole. A casing exit was milled in the expanded monobore liner to enable bypassing the BHA that was left in the hole from previous drilling operations.
The case history explored in this paper highlights overcoming substantial issues using expandable drilling liner technology via a monobore liner extension that resulted in successful installation and circulation. The preplanning, installation considerations, expansion process, lessons learned and post-deployment results will be discussed.
A Unique Stimulation Approach to Enhance Production Efficiency of Horizontal Wells in Heterogeneous Carbonate Reservoirs
Authors: Fahim Mohamed , Keshka Ashraf , Marzooqi Ayesha Al , Assreti Elamari , Helmy Hamdy , Salim Dalia , Neyaei Fardin Ali , Rafieenia Marzieh , Hudson Lisa 
Published: September 2011

Abstract
Matrix stimulation treatments are applied to improve well productivity and enhance the hydrocarbon recovery from the formation. However, in some wells optimum results cannot be achieved using conventional stimulation techniques since it is difficult to ensure efficient placement of the stimulation fluid across the entire stimulation interval. This is a prerequisite for a successful result. The situation becomes even more challenging in heterogeneous reservoirs with large permeability variations or possible presence of natural fractures in a complex geological environment.
Other complications may occur when conventional stimulation treatments keeps creating undesired wormholes throughout the same spot within existing (horizontal) bore hole. These complications may result in making future diversion jobs even more challenging and sometimes enlarges the hole to the limit of affecting accessibility in future interventions.
The paper describes a unique approach that has been successfully executed in one of the super giant onshore fields in Abu Dhabi through an extensive study over different types of heterogeneous reservoirs. The objective was to develop an economically justified stimulation strategy utilizing different treatment fluids and a unique placement approach which led to proper reservoir drainage. In this field the production comes from various carbonate reservoirs, where the different layers are subject to different methodologies to support the reservoir pressure. The approach consists of chemical diversion, dual injection for acid placement, and optimized jetting tool.
The paper also describes the results of re-stimulation of a group of wells as part of field pilot. Actual data from several treated horizontal wells are presented. The methodology of candidate selection, treatment design and execution is described along with pre and post stimulation production logging.
The paper highlights the impact of production improvements of the treated wells. Chemical diversion, as proved in the pilot wells, enhanced the acid stimulation. It was shown that previously untreated subunits, were now contributing to flow. The pilot wells have validated the engineered methodology adopted for the work-scope.
Distributed Temperature Sensing (DTS) Enables Injectivity Visualization to Enhance Stimulation Efficiency
Authors: Fahim Mohamed , Keshka Ashraf , Marzooqi Ayesha Al , Alvi Aman , Salem Dalia , Brown George , Neyaei Fardin Ali 
Published: September 2011

Abstract
Carbonate coiled tubing (CT) reservoir stimulation approaches vary, using acid systems and different diverters in order to try to achieve the best results. However, because it was not previously possible to know where the injected fluids actually go in the formation during a stimulation job, even with the enhancement of the coiled tubing placement and software model prediction, the results were often not effective as they could be.
The inclusion of a fiber optic distributed temperature monitoring system (DTS) in the coiled tubing enables visualization of different zones injectivity by monitoring the exothermal effect of the acid reaction with the carbonate in highest permeability zones and hence acid and diverter placement can be optimized for improved stimulation efficiency.
In one of Abu Dhabi Onshore fields a production log (PLT) was run in a water injector well that was completed in two different reservoirs, to provide a baseline injection profile. The acid stimulation job was then performed using fiber optic temperature monitoring through the coiled tubing, to optimize fluid placement.
One feature of the data acquired by the fiber optic distributed temperature system was that the initial baseline temperature log was able to identify the high permeability injection interval from its "warm-back" response and this was correlated with the PLT interpretation. Consequently the treatment volume was optimized using the DTS results. Another DTS run was recorded after the acid stimulation with diverter using the injection velocity approach. This consists of bull-heading water down the coil tubing annulus and tracking the hot water generated at the heel of the well from the previous shut-in as it moves across the reservoir. The velocity interpretation of the injection profile confirmed that there was minimal injection into the high permeability interval at that point of time.
The stimulation resulted in a well injectivity increase of 20% indicating successful placement and diversion of acid compared to conventional stimulation practices. The use of DTS will enable stimulating wells without the need for pre-job production log (PLT) and especially wells where a PLT is not possible either due to low flow-rates (below critical flow) or operational constrains (completion restriction).
This paper details this "first-time" experience of a coiled tubing stimulation combined with DTS measurement and injection velocity profile in the UAE. It also concludes with a list of lessons learnt and recommendations for similar future approaches.
Optimum Subsurface Production Management, Abu Dhabi, U.A.E
Authors: Kenawy Maher M. , Al Katheeri Abdulla B. , Hafez Hafez H. , Stenger Bruno A. 
Published: September 2011

Abstract
A prolific mature reservoir Unit-Y producing since the early seventies was subdivided into two major flow units, an Upper sub-zone (USZ) with Darcean permeability and a Lower sub-zone (LSZ) with permeability averaging a few tens of milliDarcy. This reservoir is part of a super giant onshore carbonate oil field undergoing secondary peripheral water flooding and operated by ADCO about 110 km southwest of Abu Dhabi. The Upper sub-zone (USZ) of the reservoir witnessed a very efficient piston-like waterflood in spite of some early water breakthrough since the early eighties due to the presence of high permeability vuggy streaks difficult to detect on conventional logs and usually not recovered during coring.
Since the late nineties, the Lower sub-zone (LSZ) was the target of an intensive development involving two hundred horizontal producers with a 3000’ long 6" openhole reservoir section. With a relatively moderate horizontal permeability, the main flooding mechanism in the Lower sub-zone (LSZ) was identified as the slumping of water from the flooded areas of the Upper sub-zone (USZ) after production drawdown from the producers in the Lower sub-zone (LSZ) was larger than the slightly negative oil-water capillary imbibition threshold initially preventing the gravity-controlled downward movement of water.
The unusual aspect of this inverted water coning situation brought a focus on the determination of the optimum production rate for the horizontal producers located in the Lower sub-zone (LSZ). A maximum production rate of 1500 blpd was assigned to the Lower sub-zone (LSZ) horizontal producers until field observations (production logging, repeat saturation logging, multi-rate testing, fiber glass casing) and the results of two pilots batches including twenty seven producers set at a higher production rate could be used to calibrate reservoir simulation models. All data acquired and studies performed over the last ten years have shown that these horizontal wells could be safely produced at a higher rate with no adverse effect on the water breakthrough timing, planned ultimate recovery or well integrity. The adoption of this higher production rate resulted in a major optimization of the business plan requirements at a time of high rig demand and with an increasingly busy surface running out of new drilling locations.
A Methodology to Determine both the Technically Recoverable Resource and the Economically Recoverable Resource in an Unconventional Gas Play
Authors: Madani HusamAdDeen S. , Holditch Stephen 
Published: September 2011

Abstract
During the past decade, the worldwide demand for energy has continued to increase at a rapid rate. Natural gas has emerged as a primary source of US energy. The technically recoverable natural gas resources in the United States have increased from approximately 1,400 trillion cubic feet (Tcf) to approximately 2,100 trillion cubic feet (Tcf) in 2010. The recent declines in gas prices have created short-term uncertainties and increased the risk of developing natural gas fields, rendering a substantial portion of this resource uneconomical at current gas prices.
This paper quantifies the impact of changes in finding and development costs (F&DC), lease operating expenses (LOE), and gas prices, in the estimation of the economically recoverable gas for unconventional plays. To develop our methodology, we have performed an extensive economic analysis using data from the Barnett Shale, as a representative case study. We have used the cumulative distribution function (CDF) of the values of the Estimated Ultimate Recovery (EUR) for all wells in a given gas play, to determine the values of the P10 (10th percentile), P50 (50th percentile), and P90 (90th percentile) from the CDF. We then used these probability values to calculate the technically recoverable resource (TRR) for the play, and determine the economically recoverable resource (ERR) as a function of F&DC, LOE, and gas price. Our selected investment hurdle for a development project is a 20% rate of return and a payout of 5 years or less. Using our methodology, we have developed software to solve the problem. For the Barnett Shale data, at a F&DC of $3 Million, we have found that 90% of the Barnet shale gas is economically recoverable at a gas price of $46/Mcf, 50% of the Barnet shale gas is economically recoverable at a gas price of $9.2/Mcf, and 10% of the Barnet shale gas is economically recoverable at a gas price of $5.2/Mcf. The developed methodology and software can be used to analyze other unconventional gas plays to reduce short-term uncertainties and determine the values of F&DC and gas prices that are required to recover economically a certain percentage of TRR.
Reservoir Optimized Fracturing - Higher Productivity From Low- Permeability Reservoirs Through Customized Multistage Fracturing
Authors: Finkbeiner Thomas , Freitag Hans-Christian , Siddiqui Mohammed , Woudwijk Roy , Joseph Kevin , Amberg Firman 
Published: September 2011

Abstract
Economic exploitation of low-permeability or tight sandstone and carbonates can be an elusive endeavor. New technologies and approaches are needed to make these more challenging reservoirs economically attractive. The completion technique discussed in this paper has been successfully employed in previously non-economic gas reservoirs in North America. The main focus of this completion technique is enhanced reservoir connectivity with the wellbore. Other completion techniques have previously been used to successfully improve reservoir contact and enhance production. These techniques are similar in their focus on improved reservoir connectivity by compartmentalizing the wellbore into multiple sections. They do, however, have their limitations in low-permeability or tight formations.
The novel completion technique presented in this paper involves horizontal drilling through a reservoir combined with compartmentalizing the wellbore into multiple sections. Each wellbore section is then individually fractured in order to effectively propagate fractures through the reservoir, thus greatly increasing productivity in each zone. Up to twenty-four zones can be set up, allowing operators to customize their stimulation program in long-reach horizontals in heterogeneous and low-permeability reservoirs. Detailed knowledge of the existing natural fracture network, the current-day stress field, and geomechanical considerations are key inputs to a valid reservoir model, reducing the risk of establishing undesired flow paths with the aquifer, for example.
This paper will illustrate how this new technology has enabled operators to benefit from significant economic improvements through operational efficiencies achieved during the drilling and completion phase based on reduced rig time and faster, more cost-efficient completions. Water shutoff options available with this new type of approach will also be discussed. Multistage fracturing leads to higher initial production, improved reservoir drainage, better control on fracture propagation, and controlled production from fractures in low-permeability sandstone and carbonate reservoirs as well as in gas-shales, which will be illustrated with case histories from these operating environments
Proactive Scale Mitigation Strategies for Simple to Complex Multilateral Producers in a Saudi Arabian Carbonate Field
Authors: Raju K. U. , Baruah K. , Al-Otaibi N. M. , Al-Shammari F. G. 
Published: September 2011

Abstract
Calcium carbonate is the most predominant scale in Saudi Aramco crude producers. Conventional phosphonate based scale inhibitor treatments are highly effective in carbonate formations. Application of new research findings in the company’s modified scale inhibitor squeeze treatment programs has significantly improved the treatment life at the lowest possible cost. These modifications resulted in better post-squeeze well response compared to more conventional treatment. However, in spite of the success of scale inhibitor treatment in vertical and conventional horizontal wells, addressing the placement of chemicals in long horizontal and complex producers, such as multilateral, maximum reservoir contact (MRC) and extreme reservoir contact (ERC) wells is always challenging and cost intensive.
A drop in operating pressure at a gas-oil separation plant (GOSP) from 450 psig to 250 psig in a carbonate field necessitated a proactive scale inhibitor treatment program. A comprehensive scale mitigation study was conducted to prioritize the treatments based on the severity of the scaling potential for all the vertical, deviated, horizontal, multilateral, and MRC wells as part of the company’s scale mitigation strategy. Conventional bullheading of chemicals from the surface into all laterals and selective lateral treatment after comprehensive lateral testing was executed as part of the trial test campaign. This paper describes/illustrates well selection criteria for priority treatment methods applied for simple to complex wells, comparison of pre- and post-production results, and a discussion of the current ongoing optimization program.
Miscible CO2 Injection in Highly Heterogeneous Carbonate Cores: Experimental and Numerical Simulation Studies
Authors: Aleidan Ahmed , Mamora Daulat 
Published: September 2011

Abstract
We have conducted a miscible CO2 flood using carbonate cores and 31° API west Texas oil under four injection modes: simultaneous water and CO2 (SWACO2), water alternating CO2 (WACO2), continuous gas injection (CGI), and waterflood (WF). Then, a pseudo-miscible black oil simulator was used to match the experimental results. The matched simulation model was extended to conduct a sensitivity study on permeability variation in the core, WACO2 ratio and slug size, and SWACO2 ratio. Three permeability values were chosen to represent a flow barrier, average matrix permeability, and high permeability streak. These values were arranged to represent a layered reservoir and then aligned in series to represent a sequenced reservoir. The four injection modes were conducted in all six permutations of these three values in both the layered and sequenced arrangements.
The oil recovery from the coreflood experiments was measured to be 90, 86, 75, and 54 % of OIIP for SWACO2, WACO2, CGI, and WF, respectively. The simulation results may be summarized as follows: for all injection modes during the layered permeability arrangements, the best oil recovery was obtained when the flow barrier is in the middle of the core. Conversely, lower recoveries were obtained when the barrier was not in the middle and the high permeability was located at the top with significant decrease in oil recovery (up to 40%). In sequenced reservoirs, each injection mode showed different preference to the permeability arrangements. For example, CGI showed higher recovery (5% increase) when the low permeability is near the outlet which allowed for more controlled displacement but with high differential pressure across the core. The WACO2 ratio study in the homogenous (base) case showed that a 1:2 ratio had the highest oil recovery but the optimum ratio was 1:1 based on the amount of injected CO2. In layered reservoirs, each permeability arrangement had higher recovery at different WACO2 ratios depending on the location of the flow barrier. However, in most cases 1:1 ratio was the optimum except for two cases, where the high permeability was at top, the 3:1 (increasing water ratio) was the optimum WACO2 ratio.