bluuebunny/crossref_metadata_2025 huggingface dataset:
Factors Controlling Recovery in Liquids Rich Unconventional Systems
Authors: Wan J. , Barnum R.S. , Digloria D.C. , Leahy-Dios A. , Missman R. , Hemphill J.
Published: May 2016

According to the U.S. Energy Information Administration (EIA), oil production in the United States reached 6.68 million barrels a day in November, 2012, its highest level since 1994. Development of hydrocarbons in deep unconventional formations via horizontal drilling and fracturing has been the main contributor to this growth. The two most impactful plays have been Bakken in North Dakota and Eagle Ford in Texas. While recognizing the success of unconventionals associated with high oil price and enhanced hydraulic fracture stimulation technologies, it is important to understand the development challenges and factors controlling recovery. The combination of limited drainage area and low resource density in unconventional systems has led to low recovery per well and challenging economics. Unconventional development has increasingly focused on liquids rich systems, especially in North America due to relatively low natural gas prices. The addition of liquids can improve overall economics, athough two phase flow impacts and complicates fluid flow and ultimate recovery. Performance of liquids rich systems is highly dependent on in-place fluid composition and phase behavior. Therefore, understanding liquids rich system phase behavior and its impact on performance is an important economic consideration. This paper discusses the drive mechanisms for unconventional plays ranging from dry gas to oil and the importance of geology and rock and fluid properties on rate and recovery. It specifically explores how the variation in liquid yield impacts rate and recovery.

Introduction

Unconventional development has increasingly focused on liquids rich systems in recent years, especially in North America, due to relatively low natural gas prices. In order to efficiently explore, appraise, develop and produce liquids rich unconventional reservoirs, it is important to understand their key characteristics. Due to low porosity, shales typically have low net hydrocarbon pore thickness and resource density. Low matrix permeability limits productivity and drainage area. These geologic constraints are countered with hydraulic fracturing, which is critical to achieving larger drainage areas and economic rates and recoveries. Liquids rich unconventional plays are also significantly impacted by large pressure gradients in the near wellbore area and by variations in rock and fluid properties. In recent years, significant progress has been made in understanding geological, petrophysical, rock and fluid characterization of unconventional plays, as well as their impact on production [1–4]. This paper provides an overview of the key factors controlling production from liquids rich unconventional plays, particularly the impact of pressure, pressure gradients, and fluid properties. Numerical and field examples are included.
Reaction Transport Modelling (rtm) in the Prediction of Dolomitisation Distribution in Carbonate Reservoirs.
Authors: Ronchi Paola , Consonni Alberto , Borromeo Ornella , Battistelli Alfredo , Geloni Claudio
Published: May 2016

The application of Reaction Transport Modelling to cases of dolomitization allows testing the genetic interpretation and may help in predicting the lateral extension of the dolomite hydrocarbon reservoir in the subsurface. The results of numerical diagenetic modelling simulations of four different dolomitization processes are presented. In all the cases the simulations suggest that the hydrogeologic system is the most important driver for dolomitization: in fact the final geometry of dolomite bodies is greatly affected by the permeability field and presence of fractured zones.

Intoduction and methods

The dolomitization processes produce alterations in the pore network system of carbonate bodies from deposition to deep burial (Machel, 2004); therefore the comprehension and the distribution prediction of the processes and their product is of paramount importance in hydrocarbon research both in explorative and development phases. A well constrained diagenetic interpretation allows assumptions to be made about the distribution of the dolomitized bodies in the subsurface. The new approach in diagenetic studies is to integrate the classical investigative techniques with the reactive transport modelling (RTM) in order to better define the conceptual models in terms of mass balance, kinetic and thermodynamic constraints (Whitaker et al., 2004). The numerical modelling applied to carbonate diagenetic systems is a fast growing discipline in the petroleum industry for its help in prediction of the extension of the diagenetic processes and related changes in petrophysical properties. Four different dolomitization models have been simulated using a sensitivity analysis approach in order to strengthen the conceptual interpretation and to evaluate the main constraints of each dolomitization process. The RTM was performed using the TOUGHREACT code (Xu et al., 2004); in this code the geochemical reactive transport is coupled to the TOUGH2 framework of multi-phase fluid and heat flow. The code calculates rock/water system evolution through the simulation of brine flux in a porous media, transport of chemical species in water solution and mineral/fluid reactions. The simulator can be applied to 1-, 2-, or 3-dimensional unstructured domains with physical and chemical heterogeneities. The first parameter to be simulated in a dolomitization reconstruction is the fluid flow into the rock. In the cases of synsedimentary dolomitization the amount and rate of fluid flow is the result of the chemio-physical conditions, for example in the reflux dolomitization the fluid flow is the direct consequence of fluid density in the system; in the dolomitization cases in which the fluid flow is linked to processes external to the area under simulation, for example in compaction dolomitization model, the evaluation of fluid flow amount and rate is to be simulated using a basin simulator (SEBE, Eni proprietory coftware).
Multi-Phase (Oil-Water) Loop Flow Test for Helical and Hybrid Passive Inflow Control Devices
Authors: Lee Byung O. , Rabeh Majed N. , Vicario Roberto , Gavioli Paolo , Garcia Gonzalo
Published: May 2016

To address the need for better understanding of multiphase fluid flow behavior through passive inflow control devices (PICDs), two-phase (oil-water) full-scale flow loop testing on helical and a new ICD design, "Hybrid" has been completed. The primary testing objective was to generate a comprehensive two-phase (oil-water) data set of flow performance curves for the helical ICD and the hybrid ICD. The test included a broad range of flow tests with varying viscosities, water cuts and pressures. The results are presented in an innovative manner using isobaric plots (isobars lines with trend lines for each viscosity value) and Reynolds number vs. Flow Coefficient plots, which can be used to easily compare different ICD performances. Test results confirm that for oil-water flow, a viscosity break point for the helical ICD occurs at 2 centipoise (cP) of medium oil. Below this break point the helical ICD does not promote water production in two-phase flow. Above this viscosity break point, the helical ICD exhibits a physical phenomenon where, at water cuts above 30%, the total flow increases at any given pressure drop promoting water flow. With regards to two-phase oil-water fluid flow, the hybrid ICD performs independently of viscosity for the range tested (up to 200 cP - maximum flow viscosity tested at the lab).The hybrid ICD consistently creates more resistance to water flow than to oil flow, causing total flow to gradually decrease at constant pressure as water cut increases. This effect was more apparent at higher pressure regimes. The functional break point of the hybrid ICD is determined to be above 200 cP.

Introduction

A comprehensive two-phase (oil-water) data set of flow performance curves for the helix inflow control devices (ICDs) and hybrid ICDs was conducted through extensive laboratory testing to identify the threshold viscosity, and to quantify single and multiphase model validity. These test results confirm that the threshold viscosity is 2 centipoise (cP). At viscosities greater than 2 cP, the test results confirm previously published findings that the helix design exhibits preferential production of water for a given pressure drop in a two-phase flow. Additionally, results verify that the helix ICD behavior exhibits correlation to the single phase model but requires a correction due to non-constant flow coefficient, and does not exhibit correlation when the fluids are multiphase, especially at higher viscosities.
Coalbed Methane Modelling Best Practices
Authors: Philpot Jared Anthony , Mazumder Saikat , Naicker Siddharta , Chang Gladys , Boostani Mohammad , Tovar Miguel , Sharma Vikram
Published: May 2016

Determining the potential range of recoverable volumes for a Coalbed Methane (CBM) prospect is a necessary precursor to a successful development plan. Several key best practices were incorporated into a workflow to consistently assess the CBM potential of numerous prospective areas.

For each area 3D static models were built based on available structural data. The models were geo-statistically populated with coal properties such as density and ash content. Correlations for other properties including gas content, permeability and Langmuir volume were developed. An analysis of the residual distribution between each correlation and its measurements was used to characterise the uncertainty in each. Several methods were considered to reproduce this uncertainty. These ranged from directly applying discrete trends, to geo-statistical property population. The effect of applying each on the predicted EUR was investigated.

Reservoir simulation models of production pilots were built and history matched. Given the complexities of the coal reservoir and the non-uniqueness of the history match, further work was carried out to capture the remaining uncertainty and determine its impact on the model predictions. Experimental design (DOE) was used to generate a population of simulation models that sampled the uncertainty range. By using the measured pilot production as a filter, this population was reduced to include only those that matched the observed production.

The final step was to optimise the placement of development wells. An algorithm that traded off the gain in gas recovery obtained by a tighter well spacing, against the increased cost associated with the extra wells was devised. The uncertainty in recovery given by this well spacing was tested using the reservoir simulation models.

Although static and dynamic modelling of CBM reservoirs is quickly becoming routine in the industry, the best practices developed while building this workflow are novel solutions to several challenges that still confound the CBM modelling community. These best practices are not unique to the study area and could easily be applied to other areas. As such this paper should provide a useful reference to those about to undertake a CBM modelling project.
Extended Use of S13Cr Materials for Downhole Production Tubing
Authors: Lee R. , Bol J.E.
Published: May 2016

Historically, martensitic stainless steels (13Cr or Super 13Cr) are known to provide a high strength, corrosion resistant production tubing material for sweet (CO2) corrosion service. The material is generally considered to be susceptible to Sulphide Stress Cracking (SSC) in sour (H2S) production environments. However, the combination of pH, temperature and chloride levels plays a significant role in altering the behaviour of this material under sour conditions. pH is commonly known to be affected by factors such as bicarbonate buffering, the presence of carbon dioxide and acids. The "self-healing" rate of chromium oxide of stainless steels is dependent upon the environment to which it is exposed, affecting its resistance to SSC.

By understanding the overall service conditions and testing the martensitic stainless steels material(s) accordingly, the use of this material has been made possible beyond commonly accepted limits without compromising its overall properties. Specific testing (cyclic slow strain rate tests), more onerous than that recommended by NACE, has been conducted for the qualification of identified martensitic stainless steels. The test regime covered both production and shut-in conditions. The results show that under the particular conditions, S13Cr materials cracking resistance differs from the limitations described by NACE MR0175/ ISO 15156.

This paper aims to highlight business cases that have led to specific testing of martensitic stainless steel and describes the significant cost savings that have been achieved by using S13Cr materials as production tubing in sour service.
Application of the Multi-Parameter Geostatistical Inversion in the Carbonate Reservoir Prediction
Authors: Liu Cai Qin , Wang Zhao Feng , Wei Xiao Dong , Zhang Da Wei , Peng Bo , Xin Chen , Peng Bo , Yang Ke
Published: May 2016

Four lithologies were developed in the study area and they were pore-bearing grainstone, compact sparite, shaly limestone and limy mudstone. The pore-bearing grainstone was the main reservoir rock. The characteristic analysis of the electrical and physical properties showed that the acoustic impedance of the pore-bearing grainstone was medium to relatively low. If we only use the inversion data of acoustic impedance, it is difficult to distinguish between the pore-bearing grainstone and other lithologies. In addition, it is difficult to distinguish the reservoir using any single given electrical parameter such as GR, density and resistivity. Therefore, we selected several sensitive logging parameters through crossplot analysis. On the basis of the geostatistical inversion, several volume data were combined, thereby the favorable reservoirs were determined.

The multi-parameter geostatistical inversion integrated and constrained by logging data and seismic data. It not only takes the advantage of the geostatistical inversion which does not simply use the acoustic impedance to joins the calculation, but it also uses the curves such as GR, porosity which directly reflect the lithology and physical properties of the formation, to join the calculation. Compared with the conventional acoustic inversion, it greatly improved the vertical resolution, finely characterized the distribution of the reservoirs, and better conquered the problem of the multiplicity of the reservoir prediction and resolution?
Artificial Lift Performance Enhancements by applying Root Cause Failure Analysis
Authors: Lapi S. G. , Arisman B. , Johnson M.  E.
Published: May 2016

This paper describes the use of a Root Cause Failure Analysis (RCFA) process to improve artificial lift systems performance: Electric Submersible Pumps (ESP) and Progressing Cavity Pumps (PCP). The subject field is remote and heavy oil environment with a wide range of production rates, fluid types, and reservoir conditions. Conditions are challenging for ESPs including severe emulsions at high water cuts, and the conditions are challenging for PCPs with relatively deep pump landing depths and high water cut. The field contains more than 800 active wells with continuous drilling operations. Pump repairs are a major part of workover rig activity. Early in the life of the field, failure rates were rapidly increasing. Collaborative efforts were established among the vendor and functional teams to address failures. The RCFA process was established with the objective to evaluate every failed pump system to determine the reason for failure, identify contributing factors, and monitor trends. The RCFA process evaluates pump performance, well test history, well intervention history, and artificial lift designs. Another key aspect of the RCFA review process is to evaluate compiled equipment teardown information. The RCFA meetings are used to share information and insure open communication among the parties. The meetings are also used to identify additional data requirements to help determine a root cause of failure. The RCFA process has led to revised equipment design and selection criteria, helped to develop new surveillance tools and processes, enabled optimized operational envelopes, and improved installation procedures. These processes and tools can be transferred and implemented successfully for other projects to help maximize value of the asset. The RCFA process was fully implemented and consistently applied since 2006 and has helped to reduce the failure frequency more than 70 % on ESPs and more than 50 % on PCPs, despite the fact that ESP population has more than tripled and PCP installations has more than doubled.
Revisiting Reaction Kinetics and Wormholing Phenomena During Carbonate Acidizing
Authors: Qiu X.  W. , Zhao W. , Dyer S.  J. , Al Dossary A. , Khan S. , Sultan A. S.
Published: May 2016

Wormholing during matrix acidizing of carbonate reservoirs is known to be predominantly mass transfer limited. Mass transfer coefficient, controlled by the fluid injection rate andthe acid diffusion coefficient, dictates the speed and profile of the wormholes.

Injection rate is easily obtained from the job execution, whereas the diffusion coefficient is intrinsically a hidden parameter of the fluid and reaction conditions. Acid diffusion coefficient data used in modeling the wormholing processes are commonly obtained at 1000 psi system pressure, which is too low to represent realistic reservoir conditions. In order to properly quantify the acid penetration inside the formation, the diffusion coefficient of acid acquired from high-pressure reservoir conditions should be used.

In this study, we investigate the effects of diffusion coefficients of HCl acid as it reacts with calcite. We use a rotating disk apparatus to obtaine the CO2-impacted kinetics at downhole conditions. The test results show that the diffusion coefficient of the HCl acid is much lower at high pressure than low pressure at the same concentration due to the impact of CO2 produced by the HCl-carbonate reaction. At higher pressure, more CO2 tends to stay in an aqueous phase, which slows down the reaction of HCl and the carbonate formation. For example, at 150 °F, the diffusion coefficient of 15% HCl at 3,000 psi reduced 50% of its original value when at 1,000 psi of 15% HCl.

This new set of kinetics data is then implemented in a 3D wormholing model to predict wormhole morphology and penetration velocity. The model uses a CT-scan rendered porosity field to capture the finer details of the rock fabric. Simulation results of fluid flow coupled with reaction provide new insights on how acidizing design models should be improved to more accurately quantify wormhole penetration, which then leads to more accurate production forecasts.
Satellite derived Bathymetry and Digital Elevation Models (DEM)
Authors: Siermann J. , Harvey C. , Morgan G. , Heege T.
Published: May 2016

In 2010, Qatar Shell Upstream International B.V. (QSUI) re-entered Exploration in Qatar focusing on the relatively deep conventional Pre-Khuff gas plays with a view to discover additional hydrocarbons in the State of Qatar. In order to support Qatar Shell with the execution of onshore and offshore seismic programs, satellite imagery was used extensively to derive added value products in terms of shallow water bathymetry, seabed classification and onshore digital elevation models (DEM).

For the offshore bathymetry and seabed classification products, 2m resolution multispectral WorldView-2 satellite scenes were processed following a data processing chain including the correction of atmospheric adjacency (increased radiance over water due to reflection of photons by the nearby land and their further scattering in the atmosphere), water surface and water column effects. The resulting offshore products had a spatial resolution of 4m and covered an area of ~700 km2. For the onshore elevation product, a 50cm WorldView-1 stereo image pair was processed using a photogrammetric stereo vision algorithm to generate a 1m spatial resolution DEM over an area of ~450 km2. The accuracy and quality of these satellite image derived products depend largely on the optical conditions of the satellite scene, the sensitivity of the satellite sensor and the accuracy of the calibration. Three types of independent control datasets were used to assess the quality and accuracy of the bathymetry and DEM; airborne LiDAR sounding transects, multibeam echo sounding swaths (offshore) and seismic survey lines (onshore and offshore). After correction for any systematic bias, the correlation of both products with the control data was found to be very good with <1m vertical error in general.

Satellite image products are recognized within QSUI as a key technology to aid the planning and preparation of seismic operations and site evaluation by improving hazard identification and reducing field risk exposure early on in the project life cycle. In addition, cost savings were realized compared to more costly traditional acquisition methods. The seismic field conditions were assessed relatively quickly compared to the time frame required for traditional methods. This allowed the data to be included in commercial tendering which in turn resulted in sharper bids.

In conclusion, satellite imagery in combination with the right processing techniques has the potential to provide an integrated wide area bathymetry and DEM coverage at relatively high resolution and low cost.
Reduction Of The Carbon Footprint In Ammonia Production Through Petrochemical Plant Integration In Qatar
Authors: Daghash Shaden , Benyahia Farid
Published: May 2016

The gas industry in Qatar is experiencing a massive growth and its energy consumption leads to significant carbon emissions specifically Carbon Dioxide (CO2). All plant operators have been required to report carbon emissions to local authorities according to international standards. However, it is not clear how carbon will be managed in the future. In this work, a potentially attractive solution for carbon management will be put forward. This work involves a case study on Ammonia production facility and the carbon footprint of the Ammonia process. The sources of CO2 investigated were from the Ammonia process itself and its main support utilities (combustion in gas turbines, steam boilers and natural gas reformers). Refering to previous work done (on Ammonia process simulation using industry standard HYSYS and process calculation using a spreadsheet), an attempt was made to recover CO2 from the process to be utilize in Urea and Methanol manufacturing. This approach was based on the concept of plant integration where Ethylene, Ammonia, Urea, and Methanol production facilities would have a certain degree of mass integration. The work highlighted the importance of the Hydrogen balance from the Ethylene facility and the extent of CO2 recovery and capture from the Ammonia facility. The results indicated that it is possible to target around 45% of CO2 produced in Ammonia manufacturing and utilize it to produce high value products such as Urea and Methanol. It was found that when excess Hydrogen is utilizaed with part of CO2 produced from Ammonia manufacturing facility, excess Methanol that is equivalent to a half a train capacity can be produced (~1424 MTPD*). In addition to that it was found that utilizing another part of CO2 with Ammonia product - that is usually gets exported - almost one train of Urea can be produced (~3728 MTPD). The concept of plant integration was found very powerful and relevant in the context of carbon management since it is known that captured CO2 in Qatar and gulf area may not be stored underground in large quantities because the geology is mainly carbonate reservoirs. The work also indicated the need to purify both CO2 and hydrogen to qualities compatible with the applications indicated. A network of hydrogen and CO2 pipelines was also highlighted in the plant integration study. This plant integration of important petrochemical processes has shown that it is possible to reduce significantly carbon emission in Ammonia manufacturing.
Mechanism and Application of Improving Heavy Oil Recovery Greatly by Solvent and Foam Assisted Steam Flooding
Authors: Jianfang Sun , Guanghuang Wu , Chuanxi Liu , Wei Li
Published: May 2016

The annual production reached 47.5 million tons in 2012 in Shengli oilfield, almost 96% of which was produced by CSS with low recovery factor of only 18.8%. Steam flooding as the main EOR technique isn't available for the heavy oil in Shengli oilfield because of the following challenges : the deeply buried depth of reservoirs (more than 1300m) results in low steam quality at bottom hole.high formation pressure makes steam zone narrower and hot water and condensation zone wider.the severe heterogeneity of reservoir causes steam channeling.

To improve greatly recovery factor after CSS, a solvent and foam assisted steam flooding (SFASF) pilot was carried out in Gudao Block 2 heavy oil reservoir. The oil production rate of small well spacing pilot increased from 20t/d to a peak of 101t/d, water cut decreased from 89% to 74.6%, and the recovery factor will be raised by 21.8% and up to 57.7% during SFASF.

The mechanism of SFASF was investigated. In order to reduce the steam channeling and improve steam uniform driving, N2 and foam agent were injected periodically during steam flooding. A new foam agent was developed, of which the resistance factor can always keep more than 20 under residual oil saturation at 300?. In order to improve displacement efficiency at hot water and condensation zone, A new anionic solvent was developed and injected during steam flooding so as to decrease oil-water interfacial tension and residual oil saturation. The solvent can make IFT up to 10-3mN/m at 300?. Moreover, optimum concentration of foam agent and solvent of SFASF is about 0.5% and 0.3% respectively and steam flooding is continuous with one month chemical system plug after three month interval. In order to get better effects high steam quality boiler by superheat, equal dryness distributing and high efficiency wellbore insulation technology were developed.

Combining heat with chemical is a trend to improve greatly heavy oil reservoirs recovery factor and the SFASF technique is available for more than 0.174 trillion tons oil reserve in Shengli oilfield.
Flow Modeling and Comparative Analysis for a New Generation of Wireline Formation Tester Modules
Authors: Kristensen Morten , Ayan Cosan , Chang Yong , Lee Ryan , Gisolf Adriaan , Leonard Jonathan , Corre Piere Yves , Dumont Hadrien
Published: May 2016

Wireline formation testing (WFT) is an integral part of reservoir evaluation strategy in both exploration and production settings worldwide. Application examples include fluid gradient determination, downhole sampling, fluid scanning in transition zones, as well as interval pressure transient tests (IPTTs). Until recently, however, formation testing was still challenging and prone to failure when testing in low-mobility, unconsolidated, or heavy-oil-bearing formations, especially with single-probe type tools. A new-generation WFT module with a 3D radial probe expands the operating envelope. By using multiple fluid drains spaced circumferentially around the tool, the new module can sample in tighter formations and sustain higher pressure differentials while providing mechanical support to the borehole wall.

We performed a detailed flow modeling-based analysis of the contamination cleanup behavior during fluid sampling with the new module. Using both miscible (sampling oil in oil-based mud) and immiscible (sampling oil in water-based mud) contamination models we studied the cleanup behavior over a wide range of formation properties and operating conditions. Comparison of the cleanup performance of the new module with the performance of conventional single-probe tools demonstrates that the new module is 10 to 20 times faster than the single-probe tools when sampling in tight formations. Finally, we also compared the new module against the sampling performance of dual packers and a focused probe.

This work is directly relevant to the planning and fundamental understanding of wireline fluid sampling. The key contributions are miscible and immiscible contamination cleanup models that include the effect of tool storage, a comprehensive analysis of contamination cleanup behavior for the new-generation WFT module with comparisons against conventional single-probe, focused probe, and dual-packer tools, and a characterization of fluid sampling conditions versus the preferred type of sampling tool.

Introduction

A logical start for any wireline formation testing (WFT) operation is a tool string design that considers the formation evaluation objectives and expected formation and fluid properties. With the current availability of an arsenal of probes having different shapes, focused probes of circular or elongated design, and dual packers, this planning stage has now become a more complex process. The recently introduced 3D radial probe (Al Otaibi et al. 2012; Flores de Dios et al. 2012) adds another choice for the engineers in planning WFT surveys.
Utilization of Onsite Nitrogen Generation Technology as a Replacement for Conventional Liquid Nitrogen for Unloading Wells: a Novel and Cost Effective Alternative with Less Carbon Footprint on the Environment
Authors: Al-Mulhim Abdulrahman K. , Al-Abdulmohsin Yousif Ahmed , Al-Khalifah Hamzah A. , Al-Shehri, Ayedh M. , El-Zefzafy Ibrahim M.
Published: May 2016

Nitrogen gas is one of the important consumables in demand in high volumes in the upstream oil industry. One of its regular uses is in the nitrogen unloading wells during kickoff operations to liven dead wells. Conventional methods use liquid nitrogen stored and transported in specially insulated vessels to be pumped into wells using sophisticated cryogenic pumps and equipment. Cryogenic equipment that operates at very low temperatures, poses several safety hazards such as causing cold burns when skin comes in contact with a severely cold object (liquid nitrogen is at -196 °C). This technical paper presents the successful utilization of in situ generated nitrogen gas at a wellsite as a replacement of the conventional requirement of liquefied nitrogen, storage and transportation system for liquid nitrogen, and cryogenic pumps and equipment for pumping nitrogen into the well.

The paper will discuss briefly the membrane technology used to produce clean nitrogen at wellsites by drawing atmospheric air as the raw input; and the advantages of the continuous nitrogen generation technology over the conventional liquid nitrogen system.

Introduction

Nitrogen gas is being used heavily in the oil industry for various operations. Unloading and reviving oil wells by reducing the hydrostatic pressure created by the fluid column inside the wellbore by pumping nitrogen using coiled tubing units is a main practice nowadays in oil fields. The conventional method being used in such cases is utilizing liquid nitrogen stored and transported in specially insulated vessels to be pumped into wells using sophisticated cryogenic pumps and equipment. This method poses some disadvantages such as gas consumption efficiency, high cost and limited quantities at wellsites especially in remote areas. Also, it positions serious safety concerns such as cold burns and accidents while transporting the liquid nitrogen. To overcome the disadvantages and minimize these safety hazards, this new approach of using onsite nitrogen generation by separation of nitrogen from the air by selective permeation through a bundle of hollow fibers has been trial tested in Ghawar field, Saudi Arabia, to meet the demand for high volume and eliminate the troublesome logistics and timing of supply while delivering liquid nitrogen to wellsites; especially in remote areas.
Determination of Reservoir Permeability Based on Irreducible Water Saturation and Porosity from Log Data and FZI (Flow Zone Indicator) from Core Data
Authors: Fazel Alavi M.
Published: May 2016

The Flow Zone Indicator (FZI) core analysis method is an accurate approach for defining different Hydraulic Units (HUs) in a well with core data, and finding accurate k-f relations for each HU according to k = Cn fxn. Determining HUs in un-cored wells from logs or geological information is the main challenge for the FZI method. Several methods have been proposed for finding HUs in un-cored wells. In many approaches, HUs are correlated with log attributes in cored wells, and this relationship is applied to un-cored wells. However, since a persistent relationship between log attributes and FZI does not exist in all litho-facies, this does not always give reliable results.

Based on a study of core and log data from several carbonate reservoirs, a practical, straightforward technique designated as the FZI-SWPHI (Flow Zone Indicator - Irreducible Water Saturation and Porosity) method is proposed. A theoretically sound relationship between FZI and Swir fe exists for a sedimentary environment. To find this relationship, FZI values from cores of the well are statistically related to the irreducible water saturation and porosity values from log data. The resulting equation, similar to the Wyllie and Rose, Tixier, Timur, and Coates equations, relates permeability directly to effective porosity and irreducible water saturation.

Unlike these general equations, however, this new equation is specific to the reservoir under investigation because constants are defined for the reservoir. The derived equation can be directly applied to wells or reservoir model grid blocks, where water saturation and porosity are known. This method is more straightforward to use and generates more precise permeability estimates with higher vertical resolution. Several examples demonstrate the accuracy and practical applications of this technique.

Introduction

The Flow Zone Indicator (FZI) method for classifying core data into Hydraulic Units (HUs) with specific FZI was introduced by Amaefule et al. (1993) and is one of the best techniques for reservoir description. This method provides accurate correlations between permeability and porosity when FZI of the reservoir rock is known. FZI is determined from core data in the cored wells and it is often applied to wells without cores through correlations with log attributes. However, existing correlation methods do not always generate accurate permeability values for wells without core data.
Production Engineering and Geoscience Integration (PEGI) as an Integrated Tool for Reservoir Surveillance and Opportunity Generation for Dukhan Field, Qatar
Authors: Negron J.  M. , Dwiyarkoro B. , Hasan W. , Abuhelaiqa A.
Published: May 2016

In an effort to integrate production performance and geological data, Qatar Petroleum developed a tool (PEGI) that assesses the current fluid front movement and reservoir behavior. The tool along with a collaborative review process, assists operation subsurface engineers and geoscientists in their evaluation of the reservoir performance while identifying new opportunities (e.g., by-passed oil) and data requirements.

PEGI links structural and stratigraphic reservoir models to production/injection data, well completion history, pressure and logging surveys, within a date, depth and layers database. This linkage provides continuous quality control by simultaneously and iteratively reviewing all data on the same platform in "real-time." The tool also ties surveillance activities with reservoir characterization and simulation efforts.

The process consists of developing mapping units based on geologic layers for interpreting fluid contacts and pressures. The engineering and geoscience data are integrated to guide the reservoir management through improved understanding of the flood front movement and dynamic behavior through time. New development opportunities can be easily visualized and analyzed both in 2D and 3D to better understand reservoir geometry and performance by multidisciplinary teamwork. Potential new well locations and areas of interest are flagged for further investigation. PEGI provides a solid understanding of reservoir geology and fluid dynamic behavior through visualization which supports the well placement process.

Introduction

Dukhan field is located onshore approximately 80 km to the West of Doha, the capital of the State of Qatar (Fig. 1). There are currently four oil producing reservoirs and one gas producing reservoir with Arab C and Arab D being the dominant. The field is a narrow anticline running north-south along Qatar's western coast. The dominant reservoirs are both structurally and stratigraphically complex carbonates. The Arab C reservoir was originally undersaturated while the Arab D reservoir was saturated with the presence of an initial gas cap. The development of the field has taken place in various stages since 1949, water dump injection started in 1965 and powered water injection to maintain reservoir pressure was taken up in stages starting from 1989. A gas recycling project in the gas cap started in 1998 and horizontal well drilling started in 1995 which later was adopted as the main development strategy since 2000.
An Investigation of Diagenesis Related to the Top Surface of the Upper Shu
Authors: Ehrenberg Stephen N. , Al-Tooqi Sabah , Al-Shukaili Mohammed , Al Habsi Naima Rashid
Published: May 2016

Core and log data from Lower Cretaceous limestones of the Upper Shu'aiba (US) Member in northwestern Oman were examined for evidence of diagenesis related to the top surface where this reservoir is overlain by shale of the Nahr Umr Formation. Cores from six vertical wells in three oilfields were studied by profiles of conventional core analyses, petrographic observations, and bulk-rock geochemical analyses. Neither bulk-carbonate stable-isotope analyses nor bulk-rock strontium concentrations show trends indicative of upward-increasing meteoric diagenesis below the top-US surface. Porosity and permeability data also show neither increasing nor decreasing vertical trends suggestive of surface-related diagenesis. Meteoric leaching and cementation may nevertheless be pervasive throughout the US reservoirs, at least partially accounting for extensive aragonite dissolution and filling of the resulting macropores with coarse calcite cement. Three of the cores show trends of upwards-increasing bulk-rock iron, manganese, phosphorous, and uranium. These effects are attributed to sea-floor authigenesis driven by reducing conditions within the upper several meters of sediment following each cycle of US sedimentation. In addition, the top 7 m of limestone in one of the cores contains several percent late saddle dolomite, and minor saddle dolomite also occurs near the tops of several other cores. Mg for dolomitization can have been provided from diagenesis of clay in the Nahr Umr Formation. The results of this study thus indicate both early sea-floor mineralization and late dolomitization in some places below the top-US surface, but do not confirm locally more intense meteoric diagenesis underlying this surface.
Mitigating Hydrates in Subsea Oil Flowlines: Consider Production Flow Monitoring & Control.
Authors: Kanu Akachidike , Al-Hajiri Nayef , Messaoud Younes , Ono Norihito
Published: May 2016

Risk of gas hydrates occurring in subsea flowlines presents serious problems to offshore oil and gas production operations. Hydrate incidents can occur in oil and gas production systems provided that the favourable compositional mix and thermodynamic conditions exist. The principal method used to mitigate hydrates in subsea flowlines is the injection of hydrate inhibitor chemicals. Thermodynamic hydrate inhibitors (THIs) have traditionally been used but these have disadvantages, namely high OPEX with increasing chemical volume demand, space constraints, high CAPEX, and safety and toxicity concerns. Recently, low dosage hydrate inhibitors (LDHIs) such as kinetic hydrate inhibitors (KHIs) and antiagglomerants (AAs) which offer advantages of minimal volume and space requirements have received considerable attention. However, widespread application of these new classes of inhibitors has been limited by yet a number of concerns including water-cut and/or subcooling temperature range limits, lack of predictive models, toxicity, biodegradability, compatibility, and produced water quality and disposal issues.

This paper presents a case study of an alternative "do-nothing" operational technique involving the comingle flow of well streams from different reservoirs at a pre-determined volume flow ratio, with temperature monitoring. Effective well-stream volume flow ratio was determined by predictive model studies of fliud systems hydrate equilibrium and pipeline operating envelops, followed by field trials. Results show that risk of hydrates in flowlines with multi reservoir fluids can be minimised by the control of the in-line fluid compositional mix by conventional flow control operation. Conceptual assessment studies suggest that this method of hydrate control could provide a cost-effective alternative to the use of chemical inhibitors, on a short-medium term basis, particularly in cases of seasonal hydrates and minimum-facility marginal oil production. Further study of effect of salinity of the produced crude on hydrate formation, given anticipated water-cut breakthrough with time, would further confirm the economics of this strategy on a field lifecycle basis.
Sub Sea Compression at Ormen Lange
Authors: Rijnbeek Roald
Published: May 2016

One of the most technically demanding developments on the Norwegian Continental Shelf, the Ormen Lange field is located 120 km offshore in 1000 meters water depth in the Møre Basin in the Southern part of the Norwegian Sea. It is a complete subsea development comprising four wellhead templates that tie back to an onshore gas processing facility at Nyhamna, where gas is dried and compressed before export to the Langeled pipelinevia the Sleipner platform to the UK.

The deep water and the seabed conditions have made the development very challenging and have necessitated novel technologies for the base project. The need for depletion compression was recognized from the initial development stages of the field and the Permit to Develop and Operate required the license partners (Shell, Statoil, Petoro, ExxonMobil, and DONG Energy) to develop subsea compression technology. This has resulted in the development of a full scale operational pilot plant to prove that subsea compression technology is viable. This paper explores the challenges that the license and Shell as operator as well as the subsea industry have overcome in developing this novel technology and outlines the future plans for the eventual selection of subsea compression as the development concept for depletion compression on Ormen Lange and elsewhere.
Mechanical Pipe Cutting in ERD Wells with Pipe Under Compression
Authors: Macfarlane Robert , Schwanitz Brian , Aguirre Marco , Greenlee James
Published: May 2016

In order to reduce rig time during workover operations, a new electric line (e-line) mechanical pipe cutting tool was deployed rigless in four ERD wells in the Middle East.

The 4-1/2" production tubing of several high deviation wells needed to be cut and pulled prior to a tubing change-out campaign, commencing February 2013. This particular mechanical cutter was chosen for its non-explosive design, where a rotating crown removes pipe wall by grinding, creating a smooth bevelled surface without shavings. This eliminates the need for a polishing trip, allows the pipe to be severed even when under compression, and leaves a cut profile in the well which is ideal for subsequently fishing. Also, this type of cutter incorporates a 'fail-safe' mechanism that prevents the tool from becoming stuck following the cut process, and the cutting crown design precludes the tendency for sticking, which is a major concern with other mechanical cutters.

In January, 2013, a system integration test was conducted to determine whether a grinding face cutter could actually cut a pipe in compression. A jig was set up to provide 20,000 lbs of compressive force on a 4-1/2", 12.6 lbs/ft pipe. The cut was made in 36 minutes. The subsequent rigless operations on four wells resulted in six successful cuts, without the requirement for the pipe to be put in neutral weight or tension. The amount of compression at the cutting depth was unknown, but at least 10,000lbs, as per the packer setting procedures.

A key benefit of mechanical pipe cutters is that they eliminate the use of explosives and chemicals which can pose HSE and operational risks, especially when simultaneous operations are being conducted. The transfer and handling of explosives may also cause additional logistical requirements and significant delays, as safety procedures are employed. In addition, this mechanical solution eliminates the need for dress runs, and tubing recovery is optimized from a rig time perspective.

This paper will discuss the operational steps taken to make the pipe cuts, a description of the new pipe cutting tool and lessons learned to improve future operations.
Implementation Of Interval Velocity Data In The Analysis Of Vertical Fluid Migration Routes And Charging Offshore Qatar
Authors: Andresen K. J. , Uldall A. , Hertle M. , Madsen L. , Perrin C. , Rameil N. , Durance G. , Tirsgaard H. , Emang M. , Gagigi T.
Published: May 2016

Oil production from the Al Shaheen Field in Block 5 and Block 5 Extension, offshore Qatar, relies on horizontal drilling and careful stimulation of the very thin and low-permeable Cretaceous carbonate reservoirs. Although the field has been in production since 1994 some uncertainties remain, particularly concerning fluid migration routes and charging of the field. The field appears to be effected by vertical anomalies which have the potential to act as vertical migration paths for fluid migration possibly impacting fluid distribution and characteristics at present day reservoir levels.

This study uses 3D seismic data combined with a calculated interval velocity volume to analyse the vertical anomalies in more detail. The anomalies are vertically extensive and typically characterized by lower velocities than the surrounding strata. They have been mapped according to their vertical extent, average velocity, any associated lateral effects, initiation and termination levels and their relation to other features in the area.

The results of the mapping suggest that the majority of the velocity anomalies are related to fluid migration with gas causing the anomalous low velocities. The present day gas cap in the Kharaib reservoir may have formed due to vertical migration of gas along the velocity anomalies, which in the area of the gas cap are associated with very low velocities and all terminate at the level of the reservoir. In the areas north of the gas cap, the velocity anomalies generally terminate shallower suggesting that fluid venting probably continued to the seafloor thereby preventing gas accumulation in the reservoirs.

The study successfully implements velocity data in the analysis of fluid migration routes and supplements the current understanding of some of the uncertainties related to the Al Shaheen Field. The results represent new inputs to the characterisation of fluid migration within the reservoirs and the existing production and may furthermore provide new input in the assessment of the future development of the field.

Introduction

Maersk Oil Qatar has since 1994 successfully produced oil from Cretaceous carbonate reservoirs in the Al Shaheen Field, offshore Qatar. The production relies on horizontal drilling in the very thin and low-permeable reservoirs. Despite the maturity of the field, several uncertainties remain for the area particularly concerning charging history and oil migration into the field.