bluuebunny/crossref_metadata_2025 huggingface dataset:
Combining Conventional and Wireline Formation Testing for Improved Reservoir Characterization
Authors: Ramaswami Shyamalan , Elshahawi Hani , El-Battawy Ahmed
Published: March 2015

Well testing has long been a valuable tool for the petroleum industry. The practice continues to be widely used today, but an increasing number of situations arise in which conventional well tests can be impractical due to cost, logistical or environmental constraints. For instance, in Arctic areas, weather conditions may dictate a time window beyond which operations must cease. In such cases, a wireline formation tester (WFT) test may present a viable alternative to acquire formation fluid samples and pressure transient data (WFT-PTA).

WFT-PTA uses a probe or a straddle packer to test a selected reservoir interval. Downhole pumps are used to clean up mud filtrate invasion and flow formation fluids at a stable rate. Downhole fluid analysis (DFA) is used simultaneously to monitor clean up and measure fluid properties such as fluid color, density, and Gas-Oil ratio (GOR) in real time. As part of the sequence, one or more pressure build up periods may be performed on each WFT-PTA station. Similar to classic well test analysis, transient pressure interpretation of the drawdown and buildup responses is used to derive the mobility thickness product and skin relevant to the rock volume investigated by the test. The permeability of that flow unit can be then calculated using the thickness of the flow unit and viscosity of the formation fluid as inputs.

In this paper, we present field data in which the integration of WFT-PTA results and fine-scale permeability indicators such as petrophysical log and core data are compared with conventional well testing using drillstem test (DST) results. We show that, as long as the scale of measurement is taken into account, and appropriate upscaling methods are used, reservoir parameters obtained are in close agreement over the same interval. In addition, the WFT-PTA reveals differences in permeability between individual flow units.

Two case studies are presented to compare independently derived permeability of the reservoirs. Permeability from WFTPTA derived from discrete intervals where WFT-PTA tests were carried out, is used to upscale continuous permeability measurements, such as Nuclear Magnetic Resonance (NMR) or Porosity-Permeability (K-PHI) derived permeability, in order to provide a better estimate of permeability over a zone to be perforated and well tested, or produced.

This integrated approach can be used to complement and calibrate well testing (DST) results or to acquire sufficient reservoir information when a full well test is not feasible and/or not required. The advantages and limitations of this approach are discussed to assist the proper selection of test types depending on desired objectives.
Multi-Azimuth, Coil Shooting And Dual Sensor Streamer Acquisition: Step Change Seismic Imaging Results In Deep Water Indonesia
Authors: Buia Michele , Tozzi Emanuele , Ravasio Alessia , Brown Peter
Published: March 2015

While wide-azimuth seismic surveys represent a routine in land environments, in marine environments things go differently. Conventional offshore 3D acquisition is still being performed mainly using narrow azimuth streamer configurations, even in structurally complex areas. Attempts at breaking this paradigm have been recently made by the industry with good results, through the acquisition of some unconventional "Multi Azimuth" (MAZ), "Wide Azimuth" (WAZ), "Rich Azimuth" (RAZ) and Coil Shooting marine surveys. Here we are presenting planning, acquisition and processing results of the advanced marine surveys, a Multi-Azimuth and a Coil shooting (Full azimuth), recently acquired by Eni e&p in Indonesia. We are also presenting a 2D test and successive 3D acquisition of a broad bandwidth (dual sensor) seismic in West Timor area, aimed at exploiting sub thrust geology. At the end we demonstrate that advanced acquisition techniques effectively provide improved geophysical images and more geological insight for exploration compared to traditional techniques.

Introduction

Towed Streamer Marine seismic acquisition generates a dataset with a limited azimuth range, of the order of 10o. In areas of complex geology, this limited azimuth collection, can result in very poor illumination of the reservoir by the seismic wave-field, due to bending and scattering of the ray-paths in the over-burden. Over the last five years, efforts to mitigate this poor illumination effect, with marine towed streamer surveys, have focused on acquisition solutions to generate seismic datasets with better azimuth distribution. The efforts included multi-direction and multi-vessels geometries to acquire surveys rich in azimuth. These techniques have proven to provide significant value in complex imaging environments; however they are constrained by the cost and availability of the multi-pass, multi-vessel operations.
From Core to Geomodel Integrated Reservoir Characterization: Example of a Carbonate Gas Field
Authors: Rebelle Michel , Cochet Fabrice , Duval Christine , Caline Bruno , Mabille Cedric , Gapillou Claude
Published: March 2015

A carbonate gas field is presently described throughout an integrated study from sedimentary context to geological model.

Petro-Geological Groups (PGG), integrated combination of sedimentology, diagenesis, petrophysics and log responses, are supporting the maps and trends for the geomodel population. On the other hand, Petrophysical Groups (PG), strictly relying on petrophysical properties, appear to be more pertinent for petrophysical parameters distribution. Petrophysics (porosity, permeability, saturation) will be consequently propagated into the geological model based on a simple relationship between PGG and PG.

With regards to saturation laws, a Wooddy-Wright-Johnson approach is proposed with min-mod-max scenarii, in order to represent the noticeable range of uncertainty, proven to be standard in carbonate environments.

Regarding the facies modeling, a supervised model provides a good result in terms of characterization and propagation of PGG for most of the studied wells whereas an unsupervised model was used to build the PGG crenel log. Furthermore, the Similarity Threshold Method (STM) computed for both models, supervised and unsupervised, highlights the good reliability of the propagation with regards to logs training set.

Permeability modeling has shown the limitation of the methodology for mono-lithological and very heterogeneous carbonate field. The prediction on cored wells, used for the training itself, provides a satisfactory result, but the prediction on un-cored intervals is not reliable. Distributions of permeability by PGs should be only based on the petrophysical synthesis results.

Such an integrated study allows maximizing the consistency and the reliability of the results, in spite of a very complex heterogeneous environment, with evidences of drains and barriers.
Effectiveness of Digital Rock Physical Laboratories In Characterisation Of Heterogenous And Complex Carbonates- A Synthesis
Authors: Mishra Prasanta Kumar , Akbar Bibi
Published: March 2015

The digital rock physics laboratories following the CT and micro CT scan techniques are in forefront and claim to carry out an accurate pore to core scale characterization of carbonate rocks with minimum possible time lapse. They measure the rock properties (porosity, permeability, electrical resistivity and elastic properties), this technique is relatively costly compared to the measurements of physical laboratories but results are obtained faster. It is known that the prediction of petro physical properties of the carbonates and assessment of multiphase flow properties in carbonates are very challenging due to complexity in the depositional processes and various digenetic changes altering the primary and even the secondary fabric of the rocks. A wide ranges of the pore and particle sizes are seen thus making the carbonate rocks heterogeneous and complex and even in a core piece of 4x6 inches a wide variation of various rock properties are noticed.

A synthesis of the data obtained from the output of three digital rock laboratories in measuring the properties of the complex, heterogeneous and tight carbonates has been made and a thorough analysis of the imaging and sampling techniques adopted by them has been critically observed. The results obtained from the high cost studies may not be the representative of the sample and may be misleading if basic assessments are not made properly by the concerned sample analyst. Although the company makes a tall claim of accuracy, the following are the critical factors that the ultimate user needs to be careful about otherwise the true value of the money spent is not obtained.
Unlocking the Limits of Sand Screen Reliability with an Innovative and Self-Adapting Technology
Authors: Yeh Charles S. , Moffett Tracy , Mayer Christian Sebastian Jakob , Bailey Nathan , Howell David A. , Barry Mike D. , Hecker Michael Thomas , Green Annabel , Gillespie George , Hall Christopher A. , McNamee Stephen
Published: March 2015

Sand screens subjected to increasingly complex and challenging environments are pushed to the limit of maintaining reliable sand control. Both preventive and reactive methods have considerably improved sand screen reliability, but the effectiveness of these methods in sustaining production is still limited by downhole uncertainties. Consequently, innovative sand screens are required to enhance sand control reliability, while maintaining operational simplicity. MazeFlo™ is one recent technology innovation from ExxonMobil designed to meet this challenge.

MazeFlo technology takes a self-adapting approach to enhance sand screen reliability. The technology utilizes a redundant sand screen and compartment maze to self-mitigate sand breakthrough caused by screen damage. The sand ingress is restricted in a local compartment without interrupting the overall well production. A 2?" prototype screen has been designed, fabricated, tested, and qualified for field installations.

This paper will highlight the qualification of this new screen through a series of mechanical tests and concludes with a field test designed to subject the screens to an extreme producing environment. The mechanical performance was evaluated under various load bearing conditions including collapse, burst, bending, torsion, tension, compression, and push-off. The results proved that there were no constraints to the self-mitigating capability of this new screen when subjected to this rigorous testing program. The field qualification test was conducted in an existing sand-prone well producing at high local flux to demonstrate screen functionality in an "uncertain" production environment versus a controlled, laboratory experiment. The field test demonstrated successful installation, downhole self-mitigating capability, and sustained sand-free production.

This unique, self-adapting technology unlocks the limits of sand screen reliability and provides an innovative and unique option for sand control completions to sustain production. The dedicated collaboration between operator and service supplier delivers continued success in developing innovative technology from concept to field installation.
Sidewall Coring: Advanced In-situ Freeze-Core Technique
Authors: Arora Aman , Bihani Abhishek Dilip , Padalkar Chaitanya Makarand , Punase Abhishek Dinesh , Patwardhan Samarth Dilip
Published: March 2015

The importance of obtaining a perfect core of a petroleum reservoir is undisputed. Despite tremendous advances in coring techniques, some basic problems remain as challenging as ever. One of these is the coring of unconsolidated formations. Most side-wall cores result in partially damaged cores, totally damaged cores or no core at all, especially in unconsolidated formations. This proposed technique promises to greatly improve the recovery, quality and longevity of the core, thereby resulting in a much better interpretation.

Freezing has long been used to preserve cores on the surface, but never before used in-situ. Here in this technique, part of the formation is frozen before being drilled out. Freeze coring promises to be highly beneficial in percussion side-wall coring, as it increases localised formation strength thus increasing impact resistance. Hence, the chances of recovering the core intact increase significantly.

This paper discusses the science of the proposed process, explains the mechanism and puts forward a new design for coring, which will help bring back virgin cores to the surface. Changes in the current techniques are proposed which is backed by experimental work.

Overall, this work will help determine petrophysical properties of the reservoir to a much higher accuracy while drilling, thus helping in identifying prolific reservoirs.
Results of Sustainable Safety Performance by building Safety Culture in a Multi-Cultural Workforce
Authors: Mataqi Ismail , Adivi Bala Siva Srikanth
Published: March 2015

Demands on the Oil & Gas industry are driving continual improvement in Health, Safety & Environment (HSE) performance, which in turn the business performance of an organization. It has been widely accepted in the industry that a structured safety culture and its implementation coupled with visible leadership and commitment directly affects HSE performance. Developing Safety Culture is a complex process, and yet it is inevitable for any organization to excel. An Organization's safety culture reflects the leadership & commitment, and values that employees share regarding HS&E.

Kuwait Oil Company (KOC), one of the premier Oil &Gas companies in the Gulf region, gives top most commitment to HSE and considers HSE as a key strategic objective of its business strategy. KOC recognized the importance of Safety Culture in not only just delivering the best decisions by the Leadership, but involves commitment to the implementation and practicing, which will form core pillars for establishing very good Safety Culture. KOC strongly believes that Safety Culture coupled with leadership and commitment act as fundamentals to HSE performance, and to business success.

Safety Culture is considered as one of the key constituents for delivering top class HSE performance in Oil & Gas Industry. This is a strong challenge for a company that is truly multicultural, employing more than 40,000 personnel (including Contractors) from over 65 different nationalities, spread through every continent of the globe. This paper describes four indicators of safety culture: Leadership, Two-way communication, Employee Involvement, Learning Culture & Attitude towards blame. These indicators have been chosen after we started saying "How can we implement Company's HSE Management System effectively that creates a culture in which continual HSE performance is achieved and safety is everyone's concern". A review of the existing safety culture was undertaken to identify details of appropriate criteria against which company performance has been assessed. Also it presents the salient findings of the existing phase of the organization (WK Fields of KOC), as a result of above four indicators and results achieved in terms of HSE performance so far.
Waterflood Conformance Control in Heavy Oil, Multilayer Reservoirs
Authors: Kalita Rintu , Ali Ehtesham , Al-Hikmani Salwa Mahmood , Al-mujaini Rahima A. Rauf , Jaspers Henri F.
Published: March 2015

This paper presents the case history of efforts made in managing the vertical conformance in heavy oil, multi-layer reservoirs. The onshore field discovered in 1985 in south Sultanate of Oman is heavily faulted, compartmentalized with multiple reservoir layers of varying permeabilities. The oil is relatively heavy with average viscosity of 60–150 cp, density of 22 degree API with low GOR. The waterflood was piloted in 1993 by adopting a 5 spot pattern. Full field waterflood was implemented in 1999.

As the waterflood in this field is characterized as one with poor vertical conformance due to varying layer permeabilities, effective conformance control is expected to result in more efficient waterflood by increasing volumetric efficiency and hence potentially increasing the recovery by 5%.

It is relevant to highlight that one dominant layer (highest permeability) contributes to most of the current oil production. Hence, profile modification changes need to keep a balance in enhancing production from other layers while not adversely affecting the contribution from this dominant layer. A multi-pronged strategy to tackle the vertical conformance control challenges has been adopted in the form of both mechanical and chemical profile control methods. The mechanical methods are to install (a) selective completion with sliding sleeves in producers, (b) dual injection through tubing and annulus after frac of low permeability layer, (c) selective completion in injectors with regulator valves/ ported sleeves, (d) casing patch, bridge plug, cement squeeze in producers and injectors. The chemical methods are (a) profile control with polymer gel in the injectors, (b) fracture shut-off with polymer-silicate gel in the injector.

As can be expected, the critical success factors in the vertical conformance control strategy are good surveillance data, understanding of interwell layer connectivity/ crossflow, selection of candidate well and remedial methods. The paper summarizes the conformance control strategies, implementation, results to date with lessons and recommendations.

Introduction

PDO operates many heavy-oil fields located in the South of Oman. These fields are clastic reservoirs with multiple layers of varying permeabilities. Water flood is a common practice in the development of these fields due to either lack of aquifer or weak aquifer and low depletion drive energy. However the heavy nature of the oil makes these water flood projects challenging due to very unfavorable mobility ratio between oil and water. Water breakthrough happens very quickly and most of the recovery takes place after water breakthrough. More pore volume injection and ability to produce to high water cut is the key to maximize recovery from these fields. Hence it is essential that the waterflood targets all the hydrocarbon bearing layers between the injector and producer to maximize the recovery of the field.
Overpressures in the Northern Malay Basin: Part 2 - Implications for Pore Pressure Prediction
Authors: Limpornpipat Orapan , Laird Andrew Paul , Tingay Mark Robert , Morley Chris , Kaewla Chaiwat , Macintyre Hamish
Published: March 2015

Examination of plots of sonic velocity against effective stress from the Northern Malay Basin indicate that fluid expansion or another unloading mechanism contribute to the total overpressure in addition to the more commonly recognised disequilibrium compaction mechanism. The aim of this study was to build a pressure prediction model from spatially extensive seismic velocity data. The pressure prediction model was calibrated by sonic velocity data acquired at well locations where extensive pressure datasets as a function of depth were measured using wireline equipment. Analysis of pressure and velocity data from wells in the Northern Malay Basin shows that pore pressure can be accurately predicted from sonic velocity using a modified Eaton approach and the seismic velocity is closely fit by filtered sonic velocity data. This modified Eaton technique requires the derivation of a robust normal compaction velocity trend and the selection of suitable empirical coefficients. The spatial variation of the fitting coefficients of an empirical normal compaction velocity and the empirical Eaton overpressure prediction relationships were assessed for 31 wells. Results show that in the Northern Malay Basin the compaction coefficient varies spatially with the geological structure and the spatial variation of the Eaton coefficient was found to be positively correlated with the magnitude of pore pressure. Accurate pressure prediction from seismic at locations away from calibration wells requires that seismic velocity analysis outputs sufficiently accurate interval velocities at a suitable resolution. The assessment of the accuracy of seismic velocities was performed on pre-stack data for a number of inlines over the study area. Seismic velocities were carefully re-picked and the resulting interval velocity at the well locations found to closely match the filtered sonic velocities. As a result of the remote nature of the seismic measurement there remains some error in the interval velocities predicted from the seismic due to the presence of shallow gas accumulations which affect the transmission of seismic energy and residual multiples in the processed reflection data.

Introduction

Drilling operations for hydrocarbon exploration and development in overpressured formations are potentially hazardous from an HSE perspective and can often lead to difficulties such as kicks, blow-outs, borehole instability issues, stuck pipe and lost circulation (Sayers, 2006). Overpressure occurs when the pore pressure at any given depth exceeds the hydrostatic pressure of a column of water (or formation brine). If the pore fluid pressure magnitude exceeds a threshold dictated by the strength of the rock, the rock will fail and no longer seal the reservoir causing the release and migration of hydrocarbons and the breaching of the trap (Dutta and Khazanehdari, 2006).
Drilling Fluids Challenges in Successful Drilling of Gotnia Formation in the State of Kuwait
Authors: Jasem Al-Saeedi Mohammed , Dakhil Al-Enezi , Arun Rajagopalan
Published: March 2015

Drilling the Gotnia formation in Kuwait has long been a drilling fluids challenge due to its sharp contrast in lithology of salt/anhydrite interfaces. Presence of this salt layer below 13,000 ft. with a thickness of 700–1,200 ft. in deep wells makes this formation more plastic in nature due to high pressure and temperature. There is a fine line between kicks and total loses in this fractured formation. Hole instability, stuck pipe, total loss, well control, acid gases and H2S are frequent problems while drilling this section.

High pore pressures exist, requiring mud weights ranging between 18.5–21.5 ppg. With this mud weight range in salt drilling, there are limited options available with the drilling fluid to ensure bore hole stability. Drilling fluids design, loss control and well control are massive tasks. Mud weight management with the knowledge of formation stresses, maintaining lowest possible rheology and managing the salt dissolution to avoid well bore closure/instability are key factors in avoiding complications in these deep wells.

OBM is utilized to drill this formation due to the insolubility of salt in oil. Historically, this formation was drilled with lower oil/water ratios resulting in high rheology along with higher mud weights causing frequent mud losses and stuck pipes. Maintaining high oil/water ratio helped to overcome the problems associated with rheology and hydraulics. Salt rapidly reduces electrical stability and oil wettability in OBM. Emulsion stability was increased as a precaution to the extremely fine particles created through salt re-crystallization which has detrimental effect on stability. Fresh water in the water phase helps to minimize salt saturation and crystallization.

This paper describes the drilling fluids challenges faced while drilling the Gotnia formation and the progress made over the years to drill this formation successfully.
Development of New Type Curves for Production Analysis in Naturally Fractured Shale Gas/Tight Gas Reservoirs
Authors: Xu Bingxiang , Li Xiangfang , Haghighi Manouchehr , Cooke Dennis , Zhang Lei
Published: March 2015

As a result of ultra-low rock permeability and hydraulic fracturing, both shale gas and tight gas exhibit long-term transient and linear flow behaviour. Previous studies have introduced type curves for linear flow and assumed that the production is dominant by the stimulated reservoir volume (SRV). The more recent type curves are developed to include the production contribution from un-stimulated region which has been assumed to be a homogeneous system. We know that some tight or shale gas reservoirs are naturally fractured and unstimulated zone is not homogeneous.

In current study, we have developed new analytical solutions (type curves) applicable for both natural fractured and hydraulic fractured shale gas/tight gas reservoirs in which both SRV and non SRV regions have double porosity flow behavior. Our developed type curves are more general and applicable for both homogenous and naturally fractured reservoirs.

Numerical models were used to validate the analytical solutions and obtained an excellent agreement. We have also developed new type curves for shale gas/tight gas evaluation. The flow regimes are identified to show linear flow and transition flow alternately, and are more complicated than the assumption of homogenous un-stimulated reservoir in late period. The parameters sensitivity of type curves was also investigated and analysed. It is shown that the reservoir size, interporosity coefficient and fracture permeability ratio have great influence on type curves while the effect of storativity ratio is not such significant because fracture porosity is very low compared to matrix porosity. We have compared the new type curves with the curves based on SRV and Brohi's solutions. It is concluded that double porosity behaviour of un-stimulated region has positive effect on production even if the fracture permeability is in the order of matrix permeability and the matrix bulk shape factor is low.
The Role of Underground Storage in Large Natural Gas Production Operation
Authors: Hoagie Merry , Amorer Gabriel , Wang Xiuli , Economides Michael J.
Published: March 2015

Underground natural gas storage has been used extensively in countries with large natural gas demand. Although much of the storage and withdrawal have been associated with seasonality, storage is becoming essential in an integrated natural gas management. It is particularly important in large operations, such as liquefied natural gas (LNG), where the total production rate must be maintained irrespective of the producing field day-to-day capacity.

Natural gas storage capacity is affected by reservoir volume and tolerable pressure (to avoid fracturing) and injection or production rates that are affected by reservoir permeability, natural reservoir drive mechanism, wellcompletion/stimulation, and the impact of cyclical losses.

We present here a new sequence of calculations and estimations demonstrating salient elements of this practice:•Maximum capacity estimation with a new type of graphical construction, blending concepts of the classical p/Z vs. cumulative recovery straight line in natural gas production.•Prediction of withdrawal rates and time, constrained by decreasing storage pressure.•Determination of maximum or sustainable withdrawal rate for a period of time. In all cases, the injecting and producing wells are hydraulically fractured. The hydraulic fractures are designed for the withdrawal rate. Thus, the required number of wells is determined.

These concepts are applied to a depleted natural gas field with an average pay of 33 ft and a permeability of 45 md. Forecasts of injection or production rates, cumulative storage or withdrawal, and pressure buildup or decline are presented as functions of time. The purpose of this case study is to sustain anLNG liquefaction operation for a specified period of time by employing under ground natural gas storage.
Hydraulic Fracture Initiation while Staged Fracturing for Horizontal Wells
Authors: Lv Zhikai , He Shunli , Gu Daihong , Zhang Hongling
Published: March 2015

Hydraulic fracturing is recognized as a successful stimulation technique for enhanced hydrocarbon recovery from unconventional tight reservoirs. Technological advancement in directional drilling has led the petroleum industry to drill arbitrarily oriented wellbores for exploitation of reservoirs, which otherwise could not be economically produced. Prediction of fracture initiation from such wellbores is therefore essential for petroleum industries to undertake efficient hydraulic fracturing stimulation tasks.

In a hydraulic fracturing process, fluid is injected under pressure through the wellbore in order to overcome native stresses and to cause failure of rocks, thus creating fractures in a reservoir. These fractures create a passage through which hydrocarbon flows into the well from the shale formation. Based on the superposition principle and elasticity theory, a total stress field mathematical model while staged fracturing for horizontal well is abstractly presented in this paper, considering systematically influencing factors such as wellbore pressure, in-situ stress distribution, seepage effect of fracturing fluid, and induced stress produced by hydraulic fracture. The law of initial and subsequent fractures initiation is studied.

The results show that the initial fracture initiation is affected by the wellbore azimuth angle, and it is easy for transverse fractures to form when the minimum in-situ horizontal stress along the wellbore direction. The stress distribution around wellbore is influenced by induced stress field, and when the initial fracture height is constant, the effect decreases gradually along wellbore direction until the combined stress field tends to the in-situ stress field. In a certain position from the initial fracture, the bigger the fracture height, the greater the induced stress, and in particular, the influence on induced stress along the wellbore direction is more obvious. Induced stress can increase subsequent fractures initiation pressure, whose level will reach 30% and increase as the fracture height increases. When fracture height is constant, the increase level of initiation pressure decreases rapidly with the increase of fracture spacing.

There is well coincidence between computational solution and measured result. Results from the analytical and numerical models used in this study are interpreted with a particular effort to enlighten the causes of abnormally high treating pressures during hydraulic fracture treatments, as well as engineers study recovery techniques.
Advanced Oxygen Enrichment Technology for Cost Effective Sulfur Recovery Processing Facility Applications in China
Authors: Wong Vincent W. , Chow Thomas K. , Zhan Yangchun
Published: March 2015

A global trend towards increasingly-stringent environmental regulations of sulfur dioxide emissions to improve air quality is faced. China has been adopting progressive policies for improvement of air quality. Recent industry trends focused on producing cleaner air and fuels around the globe, especially in China, have generated significant demand for additional hydro-desulfurization and sulfur recovery capacities in both new and existing refineries and gas plants. Oxygen enrichment technology frequently offers the most economical route to achieve the desired increase in sulfur processing capacity with high recovery efficiency.

This commercially proven technology has excellent operating safety records as witnessed by the safe operation of over 300 SRU/TGTU plants in USA, Canada, Europe, Middle East, South Africa and a newly installed facility in Panjin, China.

This paper provides a technical background of oxygen enrichment technology, and discusses the various economic, logistical, process and operational advantages that can be realized through its implementation.
Multistage Temporary Plugging Acid Fracturing Technology Application Long Interval Heterogeneous Carbonate Reservoir
Authors: Jianming Sheng , Xinrong Wu , Aijun Huang , Anpei Wang , Bin Zhao , Bo Geng
Published: March 2015

Sichuan Puguang Gas Field is high sulfur content carbonate gas reservoir buried in the depth of 4775.4~6461.3m. In the produced gas, the average content of methane is about 75%, H2S 15% and CO2 10%. The thickness of producing formation is between 176.4m~838.8m, on average, the thickness is 395m. The formation is severely heterogeneous, including type?, type? and type ? reservoir which is developed alternately. The proportion of type ? reservoir is more than 50%, the total ratio of type ? and type ? is more than 90%. Gas testing in early exploration phase obtained no commercial gas production in type ? and type ? reservoir. Using the cores from Puguang gas field reservoir, fracture flowing capacity experiments have been conducted by using various acid fracturing fluid systems and different technical models. Considering geological characters, completion situation and surface gathering conditions, large-scale temporary plugging multistage injection acid fracturing technology is selected. The plugging ratio of the temperature-controlled temporary plugging agent is more than 90% and the plugging strength is greater than 15MPa. The pump discharge capacity of the new gel acid system is 10 m3/ min. The operating friction is 30% of that of clear water. The viscosity is more than 30mPa•s after being kept for 180min under 130?. 34 wells have been acid fractured by using this technology, and the average open-flow capacity of a single well is 487.8×104m3/d. And after having been producing for one year the average gas production of a single well is 69.3×104m3/d. Multistage temporary plugging acid fracturing technology application to long well interval heterogeneous carbonate reservoir integrated with acid fracturing technology and optimized design is technical guarantee to develop Puguang Gas Field efficiently and safely, and at the same time it will also be a technology backup to develop some similar gas fields.
Production Performance Analysis of Hydraulically Fractured Horizontal Wells in Sulige Gas Field
Authors: Ruilan Luo , Yongxin Han , Shuming Yu , Jiwu Fan , Wen Xu , Ke Yuan
Published: March 2015

Sulige gas field is the largest tight sand gas field in China. In order to boost gas production of individual wells and to maximize economic return, hydraulically fractured horizontal wells are widely applied in Sulige gas field in recent years. Influenced by special geologic condition and stimulation, the production performance of hydraulically-fractured horizontal wells in tight sand gas reservoir is obviously different from that of conventional gas wells, such as:? The dominant flow regime is linear flow rather than pseudo-radial flow and this flow regime may continue for several years;? The dynamic reserve, drainage area and productivity of producing wells vary with time quickly, especially in the early stage of production.

By correctly identifying the percolation characteristics and production performance of hydraulically fractured horizontal wells in tight sand gas reservoir and combine with modern gas production analysis technology, 137multi-stage fractured horizontal wells in Sulige gas field have been analyzed. Then a prediction chart of estimated reserves and new method of dynamic deliverability evaluation for Sulige multi-stage fractured horizontal wells are established. With these chart and methods, by using early stage production data, the dynamic reserve, drainage area and deliverability of multi-stage fractured horizontal wells can be predicted effectively with elapsed production time. In this paper, ultimate recoverable reserves, drainage sizes, drainage lengths and drainage widths of 57 multi-stage fractured horizontal wells in Sulige gas field are estimated.

The results show that, in Sulige gas field, the average ultimately dynamic reserves and drainage sizes of multi-stage fractured horizontal wells are 2.8to 3.4 times that of offset fractured vertical wells, and the average initial deliverability of multi-stage fractured horizontal wells is 4.0 to 5.0 times that of offset fractured vertical wells. Based on these data, the reasonable well spacing and gas flow rate of Sulige gas field are suggested.
Polymer Flooding for Middle and Low Permeability Sandstone Reservoirs
Authors: Xiaoqin Zhang , Wenting Guan , Feng Pan
Published: March 2015

Daqing Oilfield is a heterogeneous sandstone oilfield with multi-layers. Polymer flooding in primary oil layers has obtained significant technological and economic effects. As the recoverable reserves of primary oil layers decline yearly, secondary oil layers have become the focus of industrialized polymer flooding since 2003. Compared with the primary layers in Daqing Oilfield, secondary layers are of thinner thickness, lower permeability, narrowly-developed channel sands and poor continuity of sand bodies. There are four lower aspects and two imbalances in the dynamic performance of polymer flooding in secondary layers. Due to the geological properties and recovery performances of secondary layers, measures are taken to further enhance their recovery factors. Polymer flooding objectives are carefully selected, layers are carefully divided, well spacing between injectors and producers is shortened, and separated-layer polymer injections are widely utilized. Inconsequence, better development has been obtained.
The Use of "Dope-Free" Tubulars in Petroleum Well Completions
Authors: Funes Alejandro , Figini Fernando , De Franceschi Esteban , Actis Goretta Emiliano , Castineiras Tomas , Wang Xiuli , Economides Michael J.
Published: March 2015

Although invariably well tubulars have been connected with a thread compound to prevent corrosion and the galling of the metal itself, innovative technologies have allowed the introduction of dope-free connectivity by engineering the connections at the end of pipe sections. Avoiding the use of dope compounds has apparent benefits, one of which is the prevention of formation damage. Another is the efficiency and reliability of the operation itself, removing a cumbersome, albeit routine job, a major advantage in the hectic time of a drilling rig's operation.

During the connection assembly a portion of the thread compound is exuded outside the connection and gets access to the well fluids through the tubing and annular space. Laboratory studies by us with core experiments, presented in this paper, show that the dope forms a suspension which penetrates and damages the formation. The damage is severe (more than 99 percent) and will be present in any well injection service. For production the issue is different and will depend on the reservoir permeability and the ability or lack thereof of the dope compound to penetrate the rock matrix or whether it will form a removable filter cake.

The reason that this problem has not gained widespread notice is perhaps because the problem has a narrow application of formation permeability, one that we delineate in this work. Additionally, we present evidence that the dope can be washed off usually by simple flow of reservoir fluids and/or brines orit can be partially dissolved by simple solvent treatments employing toluene orxylene.

We present here the clear benefits of using dope-free pipe connections by quantifying the negative effects of the alternative. Production equations using a dope-induced skin effect are presented, showing the detrimental impact on well performance.
From Molecular Dynamics to Lattice Boltzmann: A New Approach for Pore Scale Modelling of Multi-Phase Flow
Authors: Gong Bin , Liu Xuan , Yu Jiapeng
Published: March 2015

Absolute permeability tensor and relative permeability curves, which are the two most important properties in prediction of subsurface flow dynamics, are both obtained from lab experiments traditionally. Although the measuring approaches have been widely used and results are largely accepted for many years in most cases, the lab experiments are usually expensive, not robust especially for low and ultra-low permeability core measurements, and can not always be repeated for different fluids or under different flow scenarios.

Multi-phase modeling based on geometry information of cores obtained by Micro X-ray Computed Tomography becomes an emerging technology that tries to yield rock properties directly. Among all the methods of pore scale modeling, Lattice Boltzmann Method (LBM) shows an apparent advantage in terms of computational efficiency, readiness for parallel computing, and capability of modeling flow with complex boundary conditions. Several multi-phase LB models have been proposed in the last two decades, with successful implementation in the simulation of actual single component two phase (liquid and vapor) flow problems. But for actual solid-fluid systems, most models suffer from the parameters fitting in order to match the experimental results.

In this study, we propose to integrate Molecular Dynamics (MD) simulation with Lattice Boltzmann method to solve this problem. The basic idea is to first construct the molecular model based on the actual components of the rock-fluid system. Then MD simulation is performed to compute the interaction force between the rock and the fluid of different densities. MD simulation results indicate that the composition of the forces is a surface force as a nonlinear function of fluid density. This calculated rock-fluid interaction force, combined with the fluid-fluid force determined from the equation of state(EOS), is then used in LBM modeling. Without parameter fitting or assuming the linear relationship between the rock-fluid interaction force and fluid density, this study presents a new systematic approach for pore-scale modeling of multi-phase flow.

We have validated this approach by simulating a two-phase separation process and gas-liquid-solid three-phase contact angle. The success of MD-LBM results in agreement with published EOS solution and experimental results demonstrated a breakthrough in pore-scale, multi-phase flow modeling. Based on an actual X-ray CT image of a reservoir core, we applied our workflow to calculate absolute permeability of the core, vapor-liquid H2O relative permeability and capillary pressure curves. With the application of this workflow to a more realistic model considering actual reservoir rock and fluid parameters, the ultimate goal is to develop an accurate method for prediction of permeability tensor, relative permeability and capillary curves based on 3D CT image of the rock, actual fluid and rock components.
Qualification Testing of Large Bore, HP Tubing Retrievable Safety Valves for Gas Wells
Authors: Ali Mohammad A. , Ahmari Abdulrahman S.
Published: March 2015

Over the past decade, the role of natural gas has become increasingly important in fulfilling the ever-increasing energy needs of the world. Natural Gas has not only become an integral part of the world's energy portfolio but also offers a cleaner and more efficient fuel to help reduce carbon emissions when compared to oil. Recently, Saudi Aramco has made three major offshore, high pressure, non-associated gas discoveries. A large bore completion design was selected for these fields in order to bring these discoveries on line quickly and cost effectively.

The surface controlled, sub-surface safety valve is a critical component of the asset integrity management program for these gas wells. In order to meet the requirements of completion design and reservoir pressure, the world's first 9-5/8in 10,000psi rated TRSSSV were developed tested and qualified for these developments.

As part of qualification testing, high rate slam closure testing of the TRSSSV was carried out at the Southwest Research Institute and at GL Nobel Denton facilities. The objective of the tests was to ensure that TRSSSV closes, seals and continues functioning after a slam at the highest anticipated flow velocity in the wells. Additionally, slam test results were used to design surface and subsurface components that are required to operate the TRSSSV and must be capable of withstanding the shock load produced by a slam closure.

Two leading completion companies were selected to develop and provide the TRSSSVs for these projects. Both designs suffered initial failures, required significant modification, and underwent extensive tests before the final designs were successfully tested.

This paper discusses the basis of design, test criterion, results and lessons learned from the slam testing of the world's first 9-5/8in, 10,000 psi rated TRSSSV. The paper also provides an overview of the two test facilities used, their limitations, and recommendations for future tests.
Use of High Resolution Sequence Stratigraphy in Building 3D Reservoir Geological Model - A Case Study from Kuwait
Authors: Neog Nilotpaul , Chakraborty Subrata Kumar , Rao N.S. , Perrin Christian , Pattnaik C. , Al-Ashwak Samar , Al-Mayyas Rawan Hussain , Al-Darm Areej , Al-Ateeqi Khalid
Published: March 2015

A number of structures are producing hydrocarbons in commercial quantity from the carbonate reservoirs of Middle Marrat Formation in the Northern part of the State of Kuwait. Seismic resolution of these deep carbonate reservoirs of Toarcian age is strongly affected by multiples from overlying Gotnia-Hith salt-anhydrite layers impacting true understanding of the internal depositional architecture from seismic data making it difficult to make realistic geological models.

An extensive coring campaign adopted over a period of time for improving the understanding of depositional settings and diagenetic processes in these reservoirs and subsequent studies helped in developing a correlation based on sequence stratigraphic principles. In the Middle Marrat Formation seven cycles with sequence boundaries and maximum flooding surfaces were identified. The best reservoir facies are located in High Stand Tract, corresponding to the progradation of the carbonate platform in the form of clinoforms sloping towards the basin.

3D geological model was built with a framework base on this correlation capturing the higher order sequences with the prograding and aggrading carbonate shelf. Sedimentary facies were identified from electrologs with complete calibration from core description and ECS calibrated ELAN processing results. Gross depositional environment maps were prepared to guide the distribution of primary sedimentary facies within the model for different depositional environments like Slope/Basin, Outer Shelf, Inner Shelf, Shoreface, Barrier/ Shoal, Backbarrier/ Backshore, Lagoon, Tidal Flat, and Sabkha using templates developed for different sequence boundaries.

These carbonates are characterized by seepage reflux dolomitization process and burrows giving rise to enhanced porosity and higher productive layers. This diagenetic imprint was modeled on the primary facies in shoreface and inner shelf areas. This facies model was used to distribute other reservoir properties like porosity, permeability and water saturation using different techniques. The developed model was further calibrated with isotope geochemistry studies and was also validated from comparison with exposed and well studied geological analogue examples. This model showed better predictive capability for wells drilled subsequently.

In this carbonate reservoir, a sequence stratigraphic framework holds the key for distributing the reservoir facies within a 3D geological model in a realistic manner giving better predictability of reservoir properties and facies thereby reducing the field development uncertainty.