bluuebunny/crossref_metadata_2025 huggingface dataset:
Wealth from Waste
Authors: Al-Ghanem Fahad , Dominic Thomas
Published: November 2016

Kuwait Oil Company (KOC) owns and operates eight Gas Booster Stations with around 38 Gas Turbine drivers. These Turbines work on the Brayton Cycle exhausting hot gases to the atmosphere in an Open Cycle. Every 100 MW of Open Cycle Gas Turbine has the potential to generate 50 MW of electrical energy out of exhaust heat recovery. Considering the total installed number of Gas Turbines, there is the potential to generate 450 MW of electrical energy. The study to recover this energy, which is currently wasted, is the subject of this paper.

Traditionally the heat is recovered from the exhaust of the Gas Turbines by diverting the exhaust of the Turbines through a Heat Recovery Seam Generator. In the conventional system, the working fluid is water, which is converted into steam, which turns a steam turbo-generator. Furthermore, large quantity of water is required for cooling the steam condenser. As all the Company's Booster Stations are at dessert type of locations with difficulty in sourcing fresh water for the working fluid and seawater for condenser cooling, hence the idea did not takeoff.

We have now come to know of a heat recovery system which uses Cyclopentane as working fluid and ambient air for condenser cooling. A Thermal fluid is interposed between the exhaust gases and the Cyclopentane loop to transfer heat from the exhaust gas to the Cyclopentane loop. The pressures in the Cyclopentane loop is maintained in such a way that the heat from the Thermal Fluid converts the Cyclopentane to superheated vapor and the air in the condenser condenses it after passing through a power turbine to recover the mechanical energy. The stack will be fitted with diversion damper to direct the gas either to the heat recovery system or to the exhaust in case the heat recovery is down for maintenance without disturbing gas compression. The loss of power output from the Turbine to the Compressor shaft is negligible, only of the order of 1 to 2 %.

With the implementation of this technology, the Company can ultimately recover about 300 MW of electrical power with no additional fuel. This is a very big monetary gain, around 40 million dollars per annum. It also provides an environmental edge because this energy is obtained with absolutely no emission. At current electrical energy rates, the capital cost can be recovered in very short time. It will also give the Company all the advantages of having its own power for its development needs without depending on external agencies.
A Reversed Geo-Dynamic Approach for Brownfield Rejuvenation
Authors: Mudi Ibrahim Mahmoud , Hollmann Gregor
Published: November 2016

Brownfields are typically characterized by enormous amounts of data that include various technologies and disciplines enabling highly detailed and probabilistic models. However, data abundance often puts a threat to evaluation effectivity and to a correct identification of key controlling factors. In the E&P industry, many "sequential" approaches exist for mature field evaluation, where "static" and "dynamic" data are disconnected during the process.

The main objective of this paper is to present a new and fully integrated workflow for brownfield re-evaluation and rejuvenation. Our "reversed" Geo-Dynamic Field Modelling (GDFM) relies on simultaneous cross-discipline interaction to guarantee data consistency and is based on a full dynamic/static data coupling at a very early stage. The GDFM workflow reverses key elements of the discipline driven sequential workflow. Production and pressure data analysis comes first, not last. Field diagnosis, identification of flow units, well test re-analysis, petrophysical and geological re-interpretation are combined in cross-disciplines model constraints. These include identification of major field issues, data reliability rankings, uncertainty/certainty and impact analysis, parameter trends etc. Seismic (re−) interpretation acts as the first main integration step, honoring all available data already during horizon and fault mapping. This directly ensures a fully integrated model that – combined with seismic attribute analysis - forms the basis for static reservoir modelling and dynamic simulation.

A field example illustrates the benefits of the GDFM: a consistent history match at considerably reduced iteration time while focusing on the key controlling factors. GDFM increases model accuracy and confidence because all data sources are incorporated, honored and cross-discplinary quality controlled early in the process. The applied workflow supports uncertainty/certainty analysis for history matching, enhances the geologic model, improves the reservoir properties distributions and presents a solid base for the dynamic simulation. Though a number of minor iterations between the main work packages are still required, the case study shows that full cycle repetitions between static and dynamic modelling are avoided, which considerably reduces the time requirements of the subsurface re-evaluation and improves remarkably the studiy results.
Strategies and Best Practices for Selecting Reservoir Sector Schemes to Manage Offtake in a Waterflood
Authors: Obeta Chukwudi , Al Dhanhani Omar , Tee Aaron , Al Shehhi Budoor Hasan , Qi Zili , Li Dachang , Brantferger Kenneth
Published: November 2016

Most reservoirs, especially in carbonate systems, are characterized by heterogeneities in pore systems, permeability, diagenetic imprints, faults and lineaments, fractures, fluid systems and displacement parameters. These variable set of conditions may result in significant differences in in-place volumes as well as life cycle production behavior from different regions of the reservoir when subjected to the same depletion scheme.

To guide and control the reservoir life cycle development and management, and to leverage the full benefit of tailoring specific depletion designs suitable for specific areas of the reservoir, the asset owner has instituted a new set of guidelines on reservoir sectorization to govern all operated assets. Reservoir Sectorization could be defined as the process of outlining regions of the reservoir defined by prominent geologic features (structural, stratigraphic, diagenetic, fluid contacts, etc.) that control reservoir and well performance within which production targets can be defined, analyses conducted and surveillance plans designed.

A large offshore carbonate reservoir operated by ZADCO, which is the subject of this paper, is impacted in several ways by the aforementioned geological complexities and was deployed as a pilot to test and fully implement the new guidelines on reservoir sectorization. Previously, the existing sector pattern for the candidate reservoir was based on a five-spot flood scheme which is no longer suitable in view of the change to the current field development concept of artificial islands and long MRC wells. Therefore, in addition to compliance with the new guidelines, the key business driver for re-sectorization is to ensure sector geometries that support a line drive system, avoid wells intersecting sector boundaries and provide flexibility to adapt well placement to evolving field development challenges.

Advanced integrated workflows (analytical and simulation) were implemented and several sectorization schemes designed (1 or "no" sector, 3 sector, 4 sector, 4 quad, and 5 sector-patterns), assessed and benchmarked against defined criteria for success. Further optimizations through numerous dynamic model sensitivities led to adoption of a particular scheme that best complies with new guidelines on sectorization as well as meet the life cycle production target for the reservoir.

This paper highlights the workflows implemented, the challenges encountered and the proposed best practices in working and adopting a reservoir sectorization scheme that best enables sustainable production and maximum recovery within the constraints of the asset owners' guidelines.
Using Cf-252 as a Short Half-Life Neutron Source Provides a Safe and Reliable Porosity Alternative When Drilling in a Middle East Carbonate Reservoir
Authors: Al Arfi Saif , El Shahat Ayman , El Farouk Omar , Mostafa Hassan , El Kholy Mohamed , El Komy Mohamed
Published: November 2016

UAE environmental regulations call for minimizing exposure to radioactive waste while drilling. In depleted carbonate reservoirs, the low radiation energy, short half-life Californium-252 (Cf-252) neutron source provides a "fit for purpose" replacement to the high radiation energy, long half-life americium-beryllium (Am-Be) neutron source. With the much shorter half-life time Cf-252 neutron source, ADCO could minimize the associated liability of getting stuck downhole by eliminating the use of high energy radioactive sources with 430 year half-lives.

The Cf-252 sources emit neutrons as a result of spontaneous fission with a probability of about 3%. One gram of Cf-252 yields about 1,012 neutrons per second (n/s), which is a much higher neutron yield than Am-Be sources. A typical Cf-252 source with an activity rating of 20 mCi emits about 108 n/s compared to 16 CI from Am-Be. This fission reaction has a half-life of 2.6 years compared to 430 years for Am-Be, which means that the neutron output of the source drops by a factor of two every 2.6 years. However this reduces the useful life of the source to somewhere between 5 and 10 years. Although higher-output Cf-252 sources can be obtained to lengthen the useful life of the source, cost and safety may be issues.

To prove the effectiveness of the new source, it was decided to run the Cf-252 back-to-back with the Am-Be source. By running both sources in the same bottomhole assembly (BHA), the quality of the Cf 252 could be validated by comparing the back-to-back measurements generated from both Cf-252 and Am-Be sources. The data was compared while wiping in, wiping out, and drilling. The Cf-252 source tool was placed on the top of all other tools in the BHA in recorded memory mode. The data acquired while drilling showed a slight separation between Cf-252 porosity readings and the readings from the tool using an Am-Be. This is due to the varying formation exposure time experienced by the tool with the Cf-252 source, an invasion effect observed due to the slow rate of penetration (ROP). There is also much closer agreement between the two neutron measurements while wiping out.

This case study demonstrates the value of using a low radiation energy Cf-252 source compared to using high radiation energy Am-Be source when drilling in a depleted reservoir. A lost-in-hole Am-Be source had to be fished, which prevented the operator from plugging the well. However, using a Cf-252 source would minimize such liabilities, making the plug back procedure easier with significant savings in time and money.
Hydraulic Fracturing Application of New Seawater-Based Clean Fluid
Authors: Prakash Chetan , Raykov Tzoni , Koalsa Bartlomiej , Belakshe Ravikant , Janiczek Peter
Published: November 2016

Seawater-based fracturing fluids are favorable in offshore locations because of the readily available seawater. This can minimize or even eliminate costly vessel trips necessary to transport fresh water to rig sites, while also reducing rig downtime. This paper presents the development of a low-residue fracturing fluid that uses seawater as a base fluid and also presents the results of successful field applications.

This seawater-based fracturing fluid uses a low-residue polymer crosslinked with zirconium that has a pH of less than 10 to minimize damage and residue encountered using other fluids. The fluid was tested for rheological properties, proppant-carrying capacity, retained permeability, and compatibility with formation fluid. To improve timing and efficiency of operations, a multistage fracturing completion was used wherein each fracture sleeve was opened by dissolvable balls. Three wells were treated in the offshore Romanian Lebada fields. Well A comprised high sandstone content. Wells B and C comprised a higher limestone content but contained too much clay and sandstone for an acid fracturing treatment. Both wells exhibited a moderate-to-high number of natural fractures. Because of moderate permeabilities in the range of 0.1 to 2 md, crosslinked fluid was used in the pad and subsequent proppant-laden stages.

During development evaluations, the fluid remained stable for approximately 1 hour at 325°F with a gel loading of 6 kg/m3 (50 lbm/1000 gal) The thermal stability of the fluid system was improved when compared to the alternative hydroxypropyl guar (HPG) fluid. A delayed crosslinker was used to maintain low-friction pressure during the treatment. No scale formation was observed. The target reservoir temperature was 199°F. Additional testing optimized gel loading at 3.6 kg/m3 (30 lbm/1000 gal). The fluid suspended the proppant for approximately 2 hours. Less than 1% residue was formed after fluid breakdown, which was much lower than the residue generated by the HPG fluid. A regained permeability of 92% was obtained from a sandstone core, demonstrating the low-damaging nature of the fluid. The broken fluid was fully compatible with crude oil and completion brine.

Twenty total stages of hydraulic fracturing operations were designed and executed successfully in the three horizontal wells. A 16/20-mesh resin-coated proppant (RCP) was used at a maximum concentration of 720 kg/m3 (6 lbm/gal) during the tail stage. A total of 1533 tonnes (~3.38 million lbm) of proppant was pumped in 5915 m3 (~1.56 million gal) of crosslinked fluid.

The seawater-based fluid properties present an innovative approach for addressing the water requirement issue for offshore stimulation operations. This fluid is an excellent candidate for fracturing operations and can help operators maintain low costs per barrel of oil equivalent (BOE).
Dynamic Simulation of Major Kick for an HP/HT Well in Western China
Authors: Zhao Haiyang , Li Shuanggui , Jia Xiaobin , Sun Guo Hua , Yu Zhong , Wang Ke , Chen PeiLiang , Yu Zhong , Xu YanDong , Long Wu , Xu Liru , Gao Wei , Qiu Kaibin
Published: November 2016

As the search for petroleum has moved into the high-pressure/high-temperature (HP/HT) environment, the well control problems have continued to increase in complexity due to the small pressure margins and the large temperature-driven variations of mud properties often seen. Recently in western China, a major kick was encountered while drilling to 7874 m with 16-ppg water-based mud in an HP/HT well. Killing of the well was attempted but was not successful. After that, the drillstring broke near the top of wellbore. As a contingency action, the operator abandoned the plan for further killing and put the well into production through diverting the kick to the production pipeline. Many unknowns, which were unsolvable by conventional perceptions, were still intriguing the operator and might be issues in further drilling operations in this field. These unknowns include: (1) Why was the well pressure constant before the gas reached the wellhead while the well was shut-in for almost 2 days? (2) Where was the gas top during shut-in? (3) Why did the killing attempt fail? (4) What killing parameters should have been used in the killing attempt?

To address these unknowns and provide solid guidance for further drilling operations, simulation of the gas kick development and well killing was conducted using a dynamic hydraulic and well control simulator powered by transient multiphase flow model.

Through integration of existing well and reservoir data, the dynamic simulation was able to history match the observed wellhead pressure, casing pressure during the shut-in, and killing operations. The simulation showed that the killing pump rate was not adequate to kill this well for the given gas kick in the wellbore. The dynamic simulations successfully revealed the reason for the gas suspension in the wellbore while shut-in, predicted the gas top, and identified the required pumping rate for a success killing. The simulation also disclosed the root cause of the drillstring failure.

This case study highlights the importance of dynamic simulation during the well engineering design and before any attempt of well killing to improve chance of success for well control and safety of drilling operations.
Case Study on Remotely Operated Intelligent Plugs to Eliminate Multiple Wireline Runs in Offshore Completions
Authors: Suresh Zac Arackakudiyil , Nguyen Linh , Kannan Bharathwaj , Jung Oh Huyn , Seok Yi Jae , Luu Truyen
Published: November 2016

This paper introduces a novel application of intelligent completions using remotely operated intelligent plugs that can eliminate multiple wireline runs. This case study outlines completion of two wells in offshore Vung Tau, Vietnam using intelligent plugs. The plugs were used to test tubing, set the packer, and later act as deep-set barriers for christmas tree installation.

The wells were completed with two intelligent plugs preinstalled and run-in-hole (RIH) open. One was installed above the production packer and the other below. Use of such intelligent plugs allowed opening and closing the plugs remotely; this feature is attributed to the plugs' onboard decision-making electronics to monitor well conditions programmed to either open or close whenever a specified condition (known as a trigger) is detected. This allowed the operator to communicate to the tool remotely from the surface using applied-pressure commands.

The upper plug was closed initially to test the tubing string. It was later opened and the lower plug was closed to set the packer. The lower plug was then opened to test the packer. Both plugs were later closed to act as barriers when the blowout preventer (BOP) was removed and the christmas tree was installed. Both plugs were then opened and pulled out of hole (POOH) on wireline.

The use of remotely operated intelligent plugs helped the operator successfully eliminate eight wireline runs, saving approximately 15 hours of rig time. Considerable monetary savings were gained by removing intervention runs. Additionally, health, safety, and environment (HSE) risks associated with rigging up and running wireline were also eliminated in this case.

The industry is striving to perform completion and intervention activities in a safer and more economic manner. This case study of remotely operated intelligent plugs can be a timely addition to existing intelligent completion solutions.
Control of Hydraulic Fracture Height Growth Above Water Zone by Inducing Artificial Barrier in Western Desert, Egypt
Authors: Salah Mohamed , Gabry Mohamed A. , ElSebaee Mohamed , Mohamed Nelly
Published: November 2016

Hydraulic fracturing is frequently used to create enhanced wellbore connectivity to enable tight reservoirs to produce hydrocarbon. Many factors can be considered as risks to the success of fracturing operations. One of the risks arises in reservoirs that are close to a water-bearing zone. The risk of fracture growth into the water zone limits the stimulation options and eliminates the chances of using hydraulic fracturing treatment to improve well productivity, thereby restricting the well's future production and often resulting in lost recoverable reserves. In the Western Desert of Egypt, two wells were to be fracture stimulated with a risk of propagating into a nearby water zone. The productive pay of low-permeability reservoirs is separated from underlying water zones by a weak or no stress barrier. The proximity of the water zone to the hydrocarbon-producing zone varied from 20 to 40 ft, and containing the fracture height in such well conditions to prevent the fracture propagating into the underlying water zone becomes a serious challenge. This can jeopardize the post treatment well productivity. It therefore becomes necessary to prevent fracture height propagation from growing into the adjacent water zone.

This case study presents a novel hydraulic fracturing technique, applied for the first time in Egypt's Western Desert that controls fracture height growth in the absence of in-situ stress contrasts. This technique places an artificial proppant barrier below the pay zone, close to the water-oil contact, creating high resistance to fluid movement and restricting pressure transmission, thus arresting unbridled vertical height growth of fractures. These barriers are created prior to themain fracture treatment by pumping heavy proppant slurry at fracturing rates carried in a fracturing fluid loaded with high breaker concentrations. The high breaker concentration breaks the gel fast, thus allowing the proppant to settle quickly to the bottom of the created fracture. The results from the application of this newly applied dual fracturing treatment technique have been overwhelming, with a 12-fold increase in production with no increase in water production. The application of this technique resulted in an increase in the net pressure at the end of main fracturing treatment indicating fracture containment within the zones of interest. The minifracture analysis, stress profile calculation, fracture geometry characterization, and no water breakthrough after the treatment support the fracturing design.
Automated Technical Workflow for Smart PVT Program Design and Quality Control for Efficient Fluid Characterization
Authors: Mawlod Arwa , David Richard Mohan
Published: November 2016

PVT data is critical for fluid characterization and EOS modelling, which in turn is the key to estimate the initial hydrocarbon volumes in place, predicting reservoir dynamic behavior and production forecasting. Hence, ADCO gives high importance to have well distributed and high quality PVT data across its different reservoirs.

There are various parties involved in planning and execution of PVT studies. There have been problems associated with PVT studies workflow such as poor scope of work, data quality issues, lost historical PVT data that affects the fluid characterization and EOS modelling. In addition, there are inefficiencies due to lack of coordination amongst various activities and parties involved in the PVT studies workflow.

In this regard, ADCO embarked on standardizing and automating the entire process from PVT analysis requisition through technical data validation and archiving towards building an integrated PVT e-catalog. In our previous SPE paper (SPE-172832) we discussed our challenges, implementation strategy, and functional design phase of the project including the roadmap. In this paper discussed the progress and achievements made by ADCO towards establishing PVT intelligence Solution and integrated PVT e-catalog. The Solution enables the users to efficiently design, PVT analysis and sampling programs for a variety of fluids types and different studies such as routine, enhanced oil recovery studies, asphalltene studies. It also enables the user to perform consistent and standard validation for the PVT data during project execution

The standard scope of work for various PVT studies is predefined based on the industry standards and well defined business logic. The workflow intelligently guides the users to build the right scope of work for PVT analysis and sampling based on the business objectives and reservoir information. The solution has functionality to technically validate the data delivered by the contractors in stages through approval workflows. This is done through a smart quality control tools which is supported by business rules for various tests that enables a semi-automatic quality control for the measured PVT properties. Finally the workflow enables the users to systematically archive quality data in an integrated PVT e-catalog. The e-catalog comprise of PVT database and functionalities for quick search of PVT data across ADCO fields and reservoirs.

PVT intelligence enables the users to quickly and independently create high quality PVT sampling and analysis Scope of Work through an automated workflow. The workflow reduces the user effort and uncertainty in manual quality control for the data delivered by the laboratories and resolve data anomalies at the right time. The intelligent functionalities shall improve the quality of the PVT e-catalog which in turn enables better engineering models and calculations for Efficient Fluid Characterization.
Economic Analysis of Dimethyl Ether Production in Indonesia as Alternative Solution for LPG Demand
Authors: Kurniawan Temmy Surya , Pertamina PT , Siagian Utjok W.
Published: November 2016

In line with economic development and population growth, Indonesian energy demand has been increasing. In the past 10 years, growth of demand is around 5% per annum, on average. Indonesian energy demand is supplied primarily by oil (47%). As domestic oil resource is no longer sufficient to supply domestic demand, Indonesia energy policy objective is to move away from oil by promoting utilization of more abundantly available energy resources such as natural gas. Java Island is nation's energy demand center meanwhile Indonesian natural gas resources are located in many regions outside Java Island.

Connecting natural gas fields to the demand centers in Java would require massive investment to build gas transport and distribution infrastructure. Therefore, alternative ways of converting gas into denser energy carrier and transporting the energy using non-pipeline facilities (ships, trucks) to transport the gas to customers need to be developed. LNG and CNG are usually appropriate for large natural gas reserves and they have been developed in Indonesia. In the other hand, Indonesia still has many untapped small-medium size gas reserves. Small-medium size gas reserve (0.5-1 Tcf) is sufficient to support dimethyl ether (DME) development which could be another option for converting natural gas. DME has similar properties with LPG so it can substitute LPG. It can also substitute diesel oil used in trucks and buses. Demand for these fuels will continue to increase in the future.

This paper presents the feasibility of DME development which is assessed using wellhead netback price of gas as feasibility indicator. The netback price is calculated using the price of fuels to be substituted by the gas (in this case: LPG) as references. The basic question of this study is what is the minimum gas price at wellhead that satisfy DME project investor's economic criteria when the gas is converted to DME and the DME is to substitute LPG consumption. The minimum acceptable rate of return (MARR) as economic criteria is set at 16%.

In addition to feasibility analysis, this study also evaluates Indonesian regulatory readiness for DME development and benefits that could be gained by Indonesia as well as its risk for the implementation.
Separable Multiple-Point Geostatistical Modeling of Three-Dimensional Discrete Fracture-Vug Networks
Authors: Fadlelmula F. Mohamed M. , Qian Sun , Wang Yuhe , Fraim Michael , He Jie , Gao Sunhua , Killough John E.
Published: November 2016

Most of the world's massive fields produce from naturally fractured vuggy carbonate reservoirs. However, modeling such reservoirs is a challenging task due to the co-existence of porous and free-flow domains over a wide range of scales. Realistic characterization of fractured vuggy reservoirs requires preservation of the geological structure and reproduction of patterns. In this study, we model a discrete fracture-vug network using microtomography and multiple-point geostatistics (MPG) modeling technique. For this purpose, micro-CT scan images of a real core is used to generate two micro-scale geological models (2D and 3D reference models, which are used as original training images) with three structures; matrix, fractures, and vugs.

The structures in the reference models are also separated into matrix-fracture and matrix-vug to construct two other training images for each of the 2D and 3D original training images. The three training images are then used in MPG to generate multiple equiprobable models that mimic the original networks of the fractures and vugs. The models created using the original training images are called direct models. The others that are generated using the training images after separating the structures (matrix-fracture and matrix-vug), referred to as separable training images, are combined into fracture-vug-matrix models by superimposing the fracture networks from the matrix-fracture models on their corresponding matrix-vug models. These final three-structure models are called the combined models. The spatial continuity, connectivity, patterns reproduction, and flow performance of the generated models are compared with those of the reference models (original training images).

The results show that, the separable modeling method produces better results when used in 2D modeling, however, that is not the case for 3D modeling. All the generated realizations preserved the structures and reproduced the spatial continuity of the reference models for 2 and 3D cases. In addition, the patterns are well reproduced in both cases. However, the connectivity and the flow performance of the traditional (direct) MPG method are found to be more accurate in the 3D case than those of the separable MPG method. These results proof that the separable MPG method is not suitable for real 3D naturally fractured vuggy reservoirs modeling applications. However, more detailed sensitivity analysis of the MPG parameters could provide new insights in utilizing this method for 3D reservoir modeling applications.
Enhance Energy Efficiency Through Advanced Process Control APC
Authors: Kumar M Suresh , Ganapathy Kumar , Al Yahyaee Nawal , Ayoub Abdulla
Published: November 2016

Advanced Process Control (APC) has been used extensively to assist in operating Gas Plants for increased reliability and profitability. But the constant increase in fuel, operating, and environmental costs, coupled with constant pressure to achieve higher efficiency levels from the existing facilities, has led to looking at APC applications for enhancing the energy efficiency.

Process control of Acid Gas Removal units, Condensate Stabilizers, Utility sections, large Compressors/turbo generators which usually form part of the Gas Plants, and the need to handle feed disturbances, seasonal and ambient variations provide considerable opportunities to enable maintain stable operation, pathways for achieving high energy efficiency at the equipment/ Process Level and to strike an optimum between yield and energy performance of the gas plant. GASCO's APC implementation strategy laid sufficient emphasis on to the holistic energy scenario across the plant and incorporated that into the APC ambit in addition to the traditional control strategies for yield improvement. This approach has resulted in identifying and hence realizing higher energy efficiencies in different areas of the plant. This paper discusses the potential use of APC with an energy perspective, and describes real-life applications that will be of particular interest to Gas plants, in order to incorporate such strategies in their new/existing APC Applications and benefit as a result.
Optimization of Hydro-Fracturing Fluid for Enhanced Well Performance in Deep Volcanic Gas Reservoir
Authors: Goyal Rajat , Tiwari Shobhit , Tibbles Raymond Joseph , Anand Saurabh , Ranjan Vishal , Sidharth Punj , Pathak Shashank , Aggarwal Vishal , Shado Olushola Horatio-da-Costa , Ray Maria Fernandes
Published: November 2016

The Raageshwari Deep Gas (RDG) field in Barmer Basin was discovered in 2003 by Cairn India. The RDG field has excellent gas quality with low CO2 and no H2S. The average well depth is 3300m with bottomhole pressure of 5500 psi and bottomhole temperature of 123degC – 135 degC. Typical gas production rate is up to 12 MMSCFD with CGR of 50-60 bbl/MMSCF during initial well testing. The field is developed with 3.5" monobore vertical wells suitable for multistage hydraulic fracturing. Hydraulic fracturing treatment is required as thin laminated volcanic comprise most of the reservoir section having permeability of ~ 0.1 mD. Till date, Cairn India the operator has undertaken four hydraulic fracturing campaigns in Raageshwari gas field with over 100 successful fracs pumped in 25 wells. One of the critical components that lead to a successful hydro fracturing job is fracturing fluid. The properties of the fracturing fluid impact the fracture geometry, the proppant pack conductivity, and ultimately the productivity of the well. Extensive lab tests were done to determine the optimum fracturing fluid recipe to achieve multiple objectives such as minimum viscosity requirement, clay stabilization, effective breaking of fluid, increased fluid recovery, etc. Concentration of various additives were determined in conjunction through extensive laboratory testing. Further flowback samples were collected and tested to evaluate the correct recipe which was most suitable for Raageshwari gas wells hydraulic fracturing treatments. The current frac fluid design is the result of continuous improvement/learnings from the successive frac campaigns in Raageshwari gas field and has resulted in improved frac fluid recovery and overall well performance. This paper summarizes the basis of fluid design and various imporovements made in the frac fluid that was used in Raageshwari field. Key results and findings are discussed from over 65 lab tests performed for fluid optimization.
Characterizing a Deep Jurassic Carbonate Reservoir Using Slim Magnetic Resonance
Authors: El Dien Mahmoud Fawzy , Nugroho Cahyo , Al-Qattan Abdul Wahab , Verma Naveen Kumar , Qutainah Riyad
Published: November 2016

This paper documents first deployment of slim 4.75-inch logging-while-drilling (LWD) Magnetic Resonance (NMR) for characterizing deep Jurassic carbonate reservoir in West Kuwait. It is a complex reservoir comprising carbonate sequences having alternations of mudstone, wackestone, packstone and grainstone. Use of conventional logs presents challenges in identifying rock types with different depositional textures. The results are valuable in identifying and quantifying the carbonate rock types of varying depositional textures and support the interpretation of depositional environment across a horizontal wellbore.

The reservoir was drilled as a 6-inch horizontal well to 16000 ft, with a horizontal drain-hole section traversing 2300 ft over a depth interval thickness of around 200 feet. The NMR was run with a pre-designed setup in Dual Wait Time (DWT) mode which enabled NMR to differentiate fluids of hydrocarbon and water. The NMR T2 measurement was later processed to interpret lithology. Fluid saturation was calculated from the DWT data by exploiting the contrast in T1 polarization times between hydrocarbon and water after Rate-of-Peneteration(ROP)-flow and ROP-polarization corrections. Rock type was calculated by using parameters of T2 measurement, total and effective porosity and water saturation.

Results were classified based on the Dunham classification of depositional texture. NMR logging and processing allowed the identification of hydrocarbon bearing zones and distinguished five textures related to grain and pore size, namely: clay to siltstone, mudstone to wackestones, packstone, grainstoneandfloattstone based on core calibration of offset well. The NMR results show the presence of hydrocarbons which, however, were not clearly detected by the neutron density measurements. There are some intervals in which the neutron and density logs measure a low porosity and in which the NMR data demonstrate higher porosity and movable fluid. Calculation of hydrocarbon and water saturation indicate presence of two additional hydrocarbon bearing intervals ranging from 50 to 60 feet with low resistivity and neutron density separation.

NMR data acquisition and processing has added value for reservoir characterization in this challenging tight and heterogeneous carbonate reservoir. Identification of carbonate texture based rock types has potential for reservoir navigation and well placement particularly to distinguish tight resistive formation from hydrocarbon bearing zones. Identification of reservoir facies will help interpretation of depositional environment for reservoir development while aiding optimized stimulation and completion across long drain-hole sections.
Desanding at the Wellhead for Optimal Well Productivity and Minimal Risks to Surface Facilities
Authors: Opawale A. O. , Arreola S. , Ciprick K. , Ibouhouten B. , Kruijtzer G. L. , Verbeek P. H. , Akdim M. R.
Published: November 2016

Wellhead desanding may increase the productivity of an oil/gas well as it opens the opportunity to a minimized choked-back production. Utilizing a wellhead desanding system upstream of the choke valve, minimizes the risk of erosion of the downstream equipment as for example; valves piping, etc. In addition, better sand separation may be achieved at high pressures due to presence of dissolved gas in the crude oil. These benefits motivated the development of the Wellhead DeSander technology as a significant improvement to conventional cyclonic desanders, gravity-based sand traps and strainers.

The novel desander system utilizes a stationary non-rotating swirl element which removes sand particles from produced multiphase fluids driven by a centrifugal force. Separated sand particles are temporarily stored in an accumulator vessel designed with an automated system that detects the level of accumulated solids and initiates the flushing procedure. In this paper the development and qualification of the Wellhead DeSander technology will be extensively described.

Case studies describing flowback operations at shale plays across the US are presented. Field data is shown demonstrating the separation performance of the Wellhead DeSander at various operating conditions such as: fluid production rates in the range of 1,500 to 14,700 Barrels Per Day (BPD), produced sand concentration upto 5 % volumetric (V/V), heavy paraffinic hydrocarbon, Gas Volume Fraction (GVF) > 90 % and watercut upto 84 %. Separation performances of the Wellhead DeSander have been measured with and without an upstream conventional sand trap. Separation efficiencies upto 99 % have been achieved with the Wellhead DeSander technology. The Wellhead DeSander can provide substantial economic benefits such as reduced erosion of a process facility and minimized operating costs with sustained optimal well productivity when solids are produced.
Application of Drag Reducing Agent in Pipeline handling High Water Cut Fluid - Case Study from a Mature Field in Mumbai Offshore Region
Authors: Tiwari Amitosh , Fartiyal Prashant , Sharma Neel Mani , Manickavasagam Chandran , Toshniwal Vaibhav , Dwivedi Priyanka , Mathur Anubhav
Published: November 2016

Pipelines are usually considered the most effective and economical means for transporting fluids from satellite wellhead platforms to central processing platforms. However, the actual production from the reservoir during field life could be different than expected due to associated uncertainties in various production phases. As a result, pipeline flow assurance issues are the most common challenges faced in mid-to-late life phase of an oil field.

In mature oil fields, water cut increases with time. The total fluid flow through a pipeline may also increase due to better reservoir deliverability than expected, infill wells opportunity, workovers, zone change, gas lift deepening, etc. An increase in total fluid content causes a higher frictional pressure drop in the pipeline and increases the backpressure on flowing wells. This detrimentally affects well deliverability at declining reservoir pressure in mature fields.

A traditional approach to reduce backpressure on flowing wells is to flow the selective wells in a satellite platform. In short, the risk of increased backpressure can prevent the opening of additional available wells, thereby significantly limiting the production from a satellite platform. Another approach is to lay a new pipeline, but this is capital-intensive and time-consuming option that is often uneconomical in the late-life phase of an oil field.

This paper explores a chemical route, the application of drag-reducing agent (DRA), to address the issue of high frictional pressure drops in pipelines. DRAs have traditionally been used in pipelines handling fluid with low-to-moderate water cuts (<50%). However, their application in high water situations (fluid having water cut higher than 80%) have been rare and met with limited success.

A trial of a new DRA was carried out in a mature oil field in the Mumbai offshore region. A pipeline handling high water cut fluid (>80%) was selected for this application. This DRA is a long-chain polymer that attaches to water molecules, thereby streamlining the flow. The DRA reduces the frictional pressure by acting as a buffer along the pipe wall to decrease the amount of energy lost in turbulent flow. Application of this DRA in high water cut pipeline lowers the pressure drop with a given fluid flow, enabling the operator to flow additional wells into the same pipeline.

This paper discusses the rationale behind the identification of a problem using pipeline flow modeling (using water cut, production rates) and the selection of the appropriate chemical (considering water chemistry), along with the results from a successful field trial.

In the future, many mature oil fields will deal with issues like higher water cut fluid flow in a smaller diameter pipeline. In these situations, a drag-reducing chemical can significantly improve overall recovery.
Less Money for More Oil - Advanced Drill Cuttings Analysis Improves Post Fracture Oil Production, Wolfcamp Example
Authors: Stolyarov Sergey , Roberts Kenneth , Sadykhov Said , Rebol Amanda , Vinh Chi
Published: November 2016

"How do we reduce the cost of producing a barrel of oil and improve well productivity?" This is probably the most frequently asked question by operators. According to a US Energy Information Administration study, average drilling and completion costs in 2015 in five major unconventional plays in the US dropped 25 to 30% since 2012. Despite an overall price drop in drilling and completion, which accounts for up to 65% of capital expenditure, unconventional oil and natural gas extraction remains non profitable for many operators at current oil prices.

Increasing well productivity often requires well intervention with expensive logging tools and high-tech equipment. The use of these technologies is cost prohibitive for some unconventional plays during a market downturn, and incurs the additional risk of the loss of tools downhole.

Drill cuttings analysis during mud logging, a well-known formation evaluation tool in conventional drilling, is often overlooked or ignored in unconventional well evaluation because of the limited data from conventional techniques. However, with the development of advanced drill-cuttings analysis such as scanning electron microscope-based automated mineralogical techniques can now provide data-rich information such as brittleness, rock elastic properties and rock typing that can improve completion design and post-stimulation production. One of the main advantages of drill cuttings is that they are readily available and advanced analysis is relatively inexpensive and low-risk.

This paper reviews the use of advanced drill cutting analysis (ACA) for hydraulic fracture treatment design optimization in well 1-H in the Wolfcamp formation. The results from the review show the correlation between some formation properties obtained from the ACA and fracture treatment parameters such as treating pressure and pump rate. The post-fracture oil production of well 1-H is compared to the offset geometrically completed well. Limitations of ACA and other factors that can affect the post-stimulation production are also discussed.
Significance of Multi-Phase Pipelines Transient Analysis Using OLGA on EPC Project Schedules
Authors: Valand Bhavesh , Subramanian Senthilkumar , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama
Published: November 2016

The transient analysis of multi-phase Pipelines is primarily performed for flow assurance purposes i.e. to assure the adequacy of design to transfer wellfluids economically from the reservoir to the export line over the life of a field. The technical data considered in the study as well as the stage in project life cycle at which this study is performed, both have significant bearing on many aspects of design. These can potentially impact the overall project schedule.

Generally, the transient analysis of multi-phase pipelines using OLGA software is performed during early stages of project such as FEED which lacks the level of details required for accurate prediction of transient effects. When such details are included at later stages such as EPC, the transient results are found to be quite different impacting the procurement of long lead items and thus the project schedule.

Design of equipment such as slug catchers, separators, chemical dosing packages and pumps etc, the adequacy of equipment in brownfield projects and decision on pipeline route grading especially in cases of pumped systems are dependent on pipeline transient analysis results. For example, conventionally the slug catcher is designed based on the slug volumes predicted by transient analysis during early stages (FEED) and includes some margin. However, transient simulations with more detailed pipeline profile information provide significant differences in estimated slug volumes and increased back pressures at source. The differences in results for various actual project and potential impact on project schedule are presented in this paper.

Typically, a transient simulation model includes wellhead topside piping, infield pipelines and a common manifold connection to the inlet of slug catcher to analyze the slugging behavior of wellfluid lines and the total slug volumes at the inlet of slug catcher. These simulation models incorporate the detailed geometry of all infield pipelines as per geo-physical survey data and topside piping.

Generally, the transient simulation of pipelines during FEED are not modeled with large number of XY data of pipeline route profile, as the software takes enormous time to simulate the various transient scenarios (i.e. normal operation, turndown, ramp up and pigging). However, due to the detailed geometry of pipelines and topsides employed during EPC, the estimated slug volumes / back pressures results have significant differences, sometimes as high as 50%. This may lead to bottleneck or inadequacy of slug handling capacity for existing slug catchers if not designed with adequate margin.

The objective of this paper is to highlight the significance of multi-phase pipelines transient analysis using OLGA during EPC in finalizing the design and operating philosophy of the facility and thereby impact on project schedule in procuring long lead items based on NPCC experiences.