bluuebunny/crossref_metadata_2025 huggingface dataset:
Anisotropic Imaging of Okubotin 3D, Onshore Niger Delta
Authors: Oni Adeboye Adebowale , Madiba Gislain B. , Ozumba Bertram Maduka
Published: March 2015

With the maturity of the Niger Delta region, having been producing hydrocarbons for the past fifty years, exploration has to look deeper to find any economic accumulations. Some of the consequences of looking deeper include the onset of overpressures and velocity anisotropy. One of the measures to counter these challenges in Onshore Niger Delta is the introduction of anisotropic prestack depth migration for all newly acquired long offset 3D seismic data.

The need to properly image the deep leads to acquisition of long offset data as in Okubotin 3D survey. The consequence is that Pre-Stack Depth Migration (PSDM) based on isotropic velocity model assumptions, though effective in imaging conventional reservoirs at shallower levels, is no longer adequate. The introduction of the long offset acquisition brings about a new challenge to derive an accurate velocity model to correct for the so-called 'hockey stick' effect at long offsets. Resolution of the velocity challenge helps in the better imaging of steep dips and corrects for non-hyperbolic moveout on Common Mid Point (CMP) gathers to give better image for the deep exploration plays in the field.

This paper presents a workflow for the use of anisotropic velocity model building in Okubotin area. It discusses the possible causes of anisotropy and the impact of anisotropic Pre-Stack Depth Migration processing of seismic data in Onshore Niger Delta. Results showed a much-improved imaging of the subsurface revealing new play potentials that were hitherto unknown in the area.

The successful imaging of the deep as in Okubotin 3D has enabled the development of a standardized workflow for this process, successfully unlocked the deep play in the Onshore Niger Delta by revealing impressive leads, explained the influence of anisotropy in the region and SPDC is now able to gain full dollar value of the legacy acquired long-cable seismic data.
Blended Learning: Finding the Right Mix
Authors: Oyetola George , Efana-Okon Essien
Published: March 2015

Globalisation and digitalization has impacted all spheres of organisational life including the process of deciding which learning technique and environment is most appropriate to meet training needs of employees. This changing trend has challenged management thinking from different facets; consequently today organisations are pondering effective modes of training and learning within their contexts. As an example, since their gradual departure from solely traditional training methods as their core training methodology; organisations are beginning to realise that e-learning is not a complete replacement for traditional learning. E-learning in many contexts represents radical change, within the oil & gas industry it may appear to be a very attractive training delivery option because of its time and cost efficiencies as well as its ability to remove geographic restrictions; however the complex nature of technical activities of oil and gas companies necessitates the use of traditional delivery methods. Social contexts of organisations must be taken into cognisance if they seek to radically change their learning management systems. Blended learning involves the mixing of several delivery techniques or methods of training in the appropriate proportions according to the unique need of each training program. The variety in composition means that providers can find greater opportunities in offering trainings that will improve learning outcomes. This paper adopts the standpoint that traditional HR processes and learning methods are effective, and that technology based learning requires further consideration by organisations. It introduces a blended learning model in action within a multinational organisation and argues an integrated approach to learning; that organisational learning must be aligned to culture, strategy and context.
Water Production Surveillance Workflow using Neural Network and Bayesian Network Technology: A Case Study of Bongkot North Field, Thailand
Authors: Hermann Roland , Nitura Jonathan Tabang , Ratanavanich Suvaluck , Chandakaew Rossawan , Iemcholvilert Sevaphol , Jiraratchwaro Chawiwan , Vitoonkijvanich Siriwat , Sarisittitham Sawatdiwong
Published: March 2015

The PTTEP-operated Greater Bongkot North Area of the Bongkot gas field is selected for the pilot with around 200 active production wells and four disposal wells. High water production from the gas wells impacts well performance negatively and water-handling capacity constraints limit the volume of produced water. This warrants in many cases the shutting in of erstwhile productive wells. Potential water producing wells are identified in a time-consuming process by monitoring every well manually based on well head temperature (WHT) and pressure (WHP) trends. This leads to a delayed identification of water production wells.

A new approach with a probabilistic predictive tool has been introduced for screening potential water production wells. A data mining approach with Self Organizing Maps and Bayesian Belief Networks is used in this case study. Well head data trends and well test data are used to train Neural Network and Bayesian Belief Network models to identify potential water production wells based on pre-defined trends. The end result is a probability of potential water production based on expert user knowledge and historical data trends.

Based on the potential water production probability, well tests are run to confirm water production. Using this tool, the user can justify running production logging tools (PLTs) to identify water-contributing zones and decide on water shut off measures that can be taken.

Self Organizing Maps and Bayesian Network models have been built for Greater Bongkot North. The predictability of the models was tested with historic data. The final models gave a reasonable success rate for detecting probable water production in wells. However, it was noted that knowledge of field behavior and extending the input data beyond the original well head data is required to further improve the prediction results.

It is planned to test the workflow later this year for selected Greater Bongkot North platforms to verify the applicability of the methodology in a live environment.

Introduction

Bongkot field is located 150 km off the eastern coast of Thailand, approximately 180 km North East of Songkhla Province, in a water depth of around 80 meters. The field is intensively faulted and gas is located in several sand bodies in depth between 800 and 2800 meter. The field started production in 1993 and was originally operated by TOTAL. Since 1998 PTT Exploration & Production Plc. (PTTEP) is the operator of Bongkot gas and condensate field in the gulf of Thailand. The field has been subdivided into two main areas, Greater Bongkot North (GBN) and Greater Bongkot South (GBS). Current Bongkot hydrocarbon production comes from Greater Bongkot North Area (GBN).
TTI RTM using Variable Grid in Depth
Authors: Dai Nanxun , Wu Wei , Zhang Wei , Wu Xiaofeng
Published: March 2015

In this abstract, we discuss some practical issues related to the implementation of reverse time migration (RTM) in a tilted transversely isotropic (TTI) medium. We have proposed a methodology to effectively reduce the cost. Through optimization of the coefficients of high-order difference scheme on the variable grid, larger depth steps at greater depth can be used instead of fixed step size. Synthetic data examples are used to demonstrate the effectiveness of the methodology.

Introduction

Reverse time migration (RTM) based on solving a two-way wave equation has been one of the most accurate imaging tools available in dealing with large lateral velocity variations and complicated geology such as large dips.

RTM for isotropic and vertical transversely isotropic (VTI) medium has been routinely in use in the industry, but the application of RTM in TTI medium is still in the early stage. This lag results from the difficulties in numerical formulations for non-vertical symmetric axes and the subsequent instabilities. The TTI implementation also leads to higher computational costs compared with its isotropic or VTI counterparts.

Instead of solving the original anisotropic wave equation, several modified quasi-P wave equations were derived by different authors, that can be used to perform anisotropic RTM for P-waves imaging without cause significant S wave scattering. Alkhalifah (2000) derived a 4th-order partial differential equation (PDE) in time to describe TTI propagation. To avoid solving a high order PDE, Zhou et al. (2006) split Alkhaifah's equation into two coupled 2nd-order PDEs. However it has been observed that their equations cause instability in practice when large dip is at presence. To circumvent this stability issue, Zhang et al. (2009) pursue an equivalent TTI formulation that preserves physical energy with the kinematics retained. Fletcher et al. (2009) proposed adding non-zero shear wave velocity terms to mitigate the instability problem. Unfortunately, their solution adds numerical complexity.

In our implementation, to deal with both the stability and accuracy issues in TTI environment, we have to cut the cost dramatically to run it in production environment. To reduce the computational cost of TTI RTM, we use the least-square-root method in the Fourier domain to construct optimized finite difference (FD) schemes of variable grid in depth to approximate the first and second order derivatives. With larger steps in space in deep layers of higher velocity while keeping the same criteria for controlling the numerical dispersion, the total number of grid point is reduced. We analyzed the stability condition for this proposed FD scheme to determine the size of time step, which is related to minimum grid space, maximum velocity as well as the coefficients of FD scheme. With this implementation our RTM has been enhanced greatly in efficiency, and gained success in numerous 3D land imaging projects. Here we will demonstrate the effectiveness of this method using the 2D BP TTI model as a test case.
Redefining a Sequence Stratigraphic Framework for the Miocene to Present in Brunei: Roles of Local Tectonics, Eustacy and Sediment Supply
Authors: Torres Jose A. , Gartrell Anthony , Hogg Nick
Published: March 2015

A Play Based Exploration (PBE) approach has been applied to the Brunei onshore, principle, second and third offshore agreement areas (OAA) of the Neogene (Serravalian to recent) deltaic sequences of the Baram - Balbac Basin operated by Brunei Shell Petroleum (BSP). Previous studies, utilizing a global sequence framework, are now considered to have underestimated the influence of local autocyclic forcing, manifested through high sedimentation rates, extensional delta-top tectonics and mutli-phase crustal shortening. Integration of shelf margin trajectories, biostratigraphy and structural kinematics has enabled a revised tectono-stratigraphic framework consisting of 10 major 3rd order sequences to be established in the Late Miocene to Present section. Regional compressional pulses are at the origin of some of these sequences, with syntectonic sequences showing onlap terminations on the flanks and/or thinning on the top of inverted structures and significant dislocations in the shelf edge trajectory.

A rigorous reassessment of the biostratigraphic framework has necessitated a revision of the sequence definitions and the synethsis of these observations is detailed. Two sequence boundaries are now calibrated to two major global eustatic falls (11.7 and 5.73 Ma). The 11.7 Ma event, a period of tectonic quiescence, is linked to a ~15 km basinward shift of the shelf edge trajectory without any clear sub-aerial erosion on the emerged shelf. The 5.73 Ma event, also a period of tectonic quiescence, is linked to a more modest basinward shift of the shelf edge, but accompanied by widespread canyon incision along most of the margin, and a major incision of the fluvial system feeding the Champion Delta.

Establishing a chronostratigraphic framework in deltaic sequences deposited on active margins requires a combination of pragmatism and caution. The same sequence may show very different stratal patterns and inferred systems tract along the same margin.
TTI/HTI Anisotropy for Fracture/Faults image inside Granite Basement
Authors: Zhou Ziqiang , Ngoc Nguyen Huy , Borthwick Tom , Zhao Kai , Teng Keat Huat
Published: March 2015

The oil-bearing, fractured granite basement rocks are a very important and complicated hydrocarbon reservoir in offshore Vietnam. However, the poor S/N ratio and imaging of these steeply dipping fractures by conventional Kirchhoff migration are quite difficult to interpret for exploration. The recent development of Controlled Beam Migration (CBM) has generated a much clearer fracture image inside the basement, but the velocity inside the basement remains an issue. The imaging velocity field needs to be much slower than the well sonic velocity to produce a decent fracture image.

With the help of the CBM stack sweeping technique, we have developed a new model building flow which takes into account the complex TTI/HTI anisotropy due to the micro-fracture system inside the basement. In this flow, the azimuthally dependant velocities for fractures are first picked through CBM stack sweeping; they are then compared with the well velocity trend to estimate the TTI/HTI anisotropy parameters. The azimuth angles are further updated by CBM stack sweeping with different azimuth angles.

The resultant seismic velocities much better fit the sonic velocity logs. Also, the migrated section has much less migration swings from multiples, and the imaging of the major fault/fracture system is enhanced. Azimuth angles of the TTI (velocity) model and the improved fracture imaging provide the much needed information for the "From Seismic interpretation to Tectonic Reconstruction" methodology, which has been proven to be effective in exploration in the Cuu Long Basin for the last five years (Ngoc et al., 2010).

The existence of TTI/HTI anisotropy inside the fractured basement is demonstrated through this case study. We have presented a new velocity modelling flow which can estimate the azimuth information for fracture systems and improve the imaging quality inside the basement.
Interorganizational Relation: A Key Factor for Maintenance Contract Success
Authors: Limsoonton Tawee
Published: March 2015

Though most of maintenance functions in the Oil and Gas business usually adopt the Contract Out philosophy which is under the concept of Specialization, it does not always guarantee for success. Because E&P business usually focuses on their core business in finding and developing oil production but the maintenance activities of its operating asset are aside as a support and cost center activities. Also the E&P believes that the specialist from external could do it better both in terms of efficiency and budgetary.

This concept is acceptable if all related departments are in a good mechanism and structuring from top to bottom of the contractor's organization or from one side to the other side of the owner and contractor. But in the real world, Sirikit Oilfield (S1) has experienced poor performance of contractor because of unaligned target of the company and contractor, low competency of contractor staff, high turnover, and slow response.

To solve these problems, S1 develops maintenance organization under the 'hybrid' concept which covered under the Interorganizational Relation (IOR) paradigm. Then IOR is theoretically based upon that all of organizations are located in the environment and affected by their environment and vice versa. Then one organization is able to cause any direct and indirect effect to the other. Under the environment of contract condition, one organization performance also affects the other one's performance no matter if they are owner or contractor. The competency and management system of S1 maintenance staff does not affect only to its own performance but also the performance of the contractor.

This concept delimits any incompetent of the contractor by transferring any work control of the contract staff to be under the accountability of S1 own staff. On the other hands the contractor will be responsible for competency management and benefit-compensation management.

Since 2007 which this concept has been introduced, the achievement of contractors' KPI improves from 74.4% in 2008 to be 98.2% in 2009. SSHE activities score at 86%, Inspection Compliance / CM- PM Compliance > 95%.
Developing a Stage Tool for Cemented Back Monobore Completions with Open Hole Multi-Stage Systems in the Montney
Authors: Kimmitt Kyle Patrick
Published: March 2015

Challenges associated with cementing horizontal wellbores, as well as the higher operational time and costs associated with the cemented liner, plug and perf method, has resulted in many operators switching to open hole multi-stage system (OHMS) completions. In addition, production increases have been realized with OHMS due to access to the entire open hole lateral.

To further optimize economics, cemented back monobore completions with OHMS are becoming the completion method of choice for operators. This is because they save on wellbore costs by eliminating the intermediate casing. Instead, the build section of the wellbore is cemented back to surface using a stage tool once the liner is installed. In addition, the cemented back method allows for OHMS systems to be run in on liner eliminating the need to trip out the running string and trip in the frac string.

This paper outlines the operational procedure for cemented back monobore OHMS completions. Due to various issues with conventional plug-type cementing stage tools a new hydraulically activated, mechanically closed cementing stage collar was designed to open/close without the use of a plug/dart. The new stage tool addresses the operational issues encountered with conventional tools and further reduces costs by reducing rig time. With the new stage collar, there is no drill out of plugs and cement after the cementing operation, eliminating debris that could be problematic for the OHMS functioning.

The development of the new stage collar through lab testing and field trials is discussed. This technology has been successfully used in various formations in Canada and the United States. This paper presents case study examples of installations in the Montney formation.

Introduction

Geology of the Montney.

The Montney formation covers an area of approximately 246,000 km2 (95,000 sq. mi.) stretching across Alberta and British Columbia (Figure 1). It is a leading example of an unconventional gas play in the Western Canadian Sedimentary Basin containing vast quantities of proven gas reserves. Estimates of gas in place are up to 700 Tcf.

The Montney consists of four distinct intervals: the Upper, Middle, Middle Lower and Lower (National Energy Board, Canada). Characterized by its low permeability (0.01 - 0.5 mD) and thick stack, the Montney is a prime candidate for horizontal drilling and hydraulic fracturing techniques. The formation is a blend of sandstone, siltstone and shale intervals with porosity up to 8% and true vertical depth to 3,950 m (13,000 ft).
Evaluation of Stress Anisotropy of the Formation by Utilizing Dipole Shear Sonic Imager (DSI*), Formation Micro Imager (FMI*) and Density logs. A Case Study on Kanawara Field, South Cambay Basin, India.
Authors: Pachineelam Subrahmanyam , Paluri Bharat Sactry , Mudigonda Anand Siva Kumar , Jagannadha Rao Nagavaradu Dharma
Published: March 2015

Knowledge on Stress anisotropy of the formation is vital to understand the stress direction and magnitude. A stress direction allows well bore stability analysis for safe and cost effective drilling in a challenging environment. Well bore stability analysis showed a large tectonic imbalance between minimum and maximum horizontal stress. As a result, wells drilled in the direction of maximum horizontal stress will have a significant increase in wellbore stability problems compared to those drilled in the direction of minimum horizontal stress. Perforations to be oriented consistent with stress direction to optimize the production and minimize sanding problems. Identification of anisotropy due to fractures leads to enhanced production and maximize the oil recovery from the hydraulic fracturing job.

Well bore stability analysis (WBS) of Kanawara field can be performed by define the rock properties such as Young's modulus, Shear modulus, Poisson's ratio and elastic properties like unconfined compressive strength (UCS) and friction angle of the formation. WBS is a numerical representation of rock mechanical properties, in-situ stresses and pore pressure for a specific stratigraphic section in a field. Compressional slowness (DTCO) and shear slowness (DTSM) along with density (RHOB) log are basic wireline measurements used in determining formation mechanical properties in the vicinity of well #1.

The geomechanical study was conducted by utilizing data from all domains, which included wireline data mainly Dipole sonic (DSI*), FMI* and Density logs. Drilling and completion reports, mud logs, MDT tests, minifracture tests, injectivity tests and LOT values are used for calibration purposes.
New Mathematical Models for Calculating the Proppant Embedment and Conductivity
Authors: Gao Yuanping , Lv Youchang , Wang Man , Li Kewen
Published: March 2015

Proppant embedment plays a significant role in decreasing fracture aperture and conductivity, especially for weakly consolidated sandstones, shale (oil and gas) rock, and coal beds. Empirical and semi-empirical models were usually used to calculate the embedment of proppants. However the accuracy of matching or predicting the proppant embedment using these existing models may not be satisfactory in some cases. On the other hand, it is difficult to determine the coefficients of these models. In this study, analytical models were derived to compute the proppant embedment and fracture conductivity. These new models can be used to calculate the proppant embedment, proppant deformation, the change in fracture aperture and fracture conductivity in the ideal or experimental situations of either single-layer or multi-layer patterns in the fractures under closure pressures. The new models showed that the proppant embedment and fracture conductivity are affected by the factors of closure pressure, fracture aperture, the elastic modulus of proppant and coal bed, the size of proppant, the concentration of proppant-paving, etc. Experimental data of proppant embedment in fractures and fracture conductivity of different proppants at different closure pressures were used to test the models derived in this study. The results from matching the experimental data using the new and the existing models were compared. The results showed that the new models especially the revised new models could match the experimental data in all of the cases studied. The new models for calculating the proppant embedment and fracture conductivity with a better accuracy are of great significance in selecting proppants, which is helpful to achieve high fracture conductivity and then high oil or gas productions of conventional, especially unconventional resources such as shale oil, shale gas, and coal bed methane.
The Study and Application of High Temperature-Resistant Solid Expandable Tubular Technology
Authors: Li Yiliang , Chen Qiang , Gao Xiangqian , Li Tao , Han Weiye , Bi Xiuling , Sun Qiang
Published: March 2015

The introduction of solid expandable tubular has been successful in the oil and gas industry, normally nitrile-butadiene rubber was vulcanized outside the tubular in order to seal off the annulus between the tubular and the wellbore, and the rubber may fail at about 400K temperature, making the tubular incapable while applied in high-temperature wells.

To solve this problem, two kinds of materials aimed at replacing the rubber were considered, one is copper which could be welded upon the tubular, and the other is the steel which is the protruding part of the SET body and can be obtained through machining process. Firstly full-scale expansion tests were performed to compare the impact of copper and steel on the expansion force, given the same length and post expansion interference; secondly the experiments aimed at understanding the sealing ability of the two new materials were carried out in the simulative environment of 673K.

The results showed that the use of copper and steel witnessed increased expansion pressure about 10% and 20% respectively compared to rubber, when the two materials were put into 673K environment for pressure testing, both copper and steel demonstrated instable results due to the irregular shape of the casing, therefore the right strategy was to set up sealing components at different part of the SET to increase the chance of success. The test results demonstrated that generally 0.5mm post expansion interference was enough for both to function well at 25MPa. The steel was more reliable than the copper since the latter demands additional process to be integrated with the SET and the field application of the casing patching in the high temperature well selected steel as the sealing material, two months after the operation, the steel passed the test of 15MPa without any leak.

We expect this research will contribute to improving the high-temperature resistant ability of expandable tubular, and will help form the technical basis for the future application in some extreme conditions.
Foam Assisted Air Injection (FAAI) for IOR at Hailaer Oilfield: Prospects and Challenges
Authors: Bo-jun Wang , Jin-zhong Liang , You-wei Jiang , Fan-zhong Kong , Jia-chun Wang
Published: March 2015

The Xi11-72 Block, located in Hailaer Oilfield, Inner Mongolia Autonomous Region, China, contains many ultra-low permeability (<2.0×10-3µm2) oil reservoirs, with natural fractures. The reservoir temperature is 82°C; the original reservoir pressure is approximately 22.5 MPa; and the water-sensitive index of the reservoir is high (>0.7). Primary production and limited water flooding experience at adjacent Blocks have shown that the recovery factor in these reservoirs is very low due to lack of reservoir energy and poor water injectivity. Since 2009, Foam Assisted Air Injection (FAAI) has been proposed, in order to block natural fractures, maintain reservoir pressure and/or increase sweeping and displacement efficiency. A series of laboratory experiments have been conducted to study the oxidation kinetics of air/air foam with oil and the blocking and displacement efficiency of air foams in different oil sands. Reservoir simulation has also been carried out for predicting the reservoir response to foam assisted air injection and optimizing the injection process. Air injection pilot test started in the field since 23 April 2011 in a well group with 1 injector and 6 producers, using a Skid-mounted high pressure air compressor (40 MPa, 7 m3/min air rate). Oxygen breakthrough was observed (oxygen contents 3.7%) on 13 May 2011, and then assisted foam was injected to inhibit air breakthrough. Up to 30 June 2011, five foam slugs had been injected into the reservoir. The field results show that air injection can enhance injection capacity; assisted foam injection can inhibit air breakthrough effectively; and oil production can be significantly increased with water cut reduced by 4%. The detailed laboratory study, field experience and prospects and challenges analysis are presented in this paper.
Effect of Porous Media on Saturation Pressures of Shale Gas and Shale Oil
Authors: Pang Jianyuan , Zuo Julian , Zhang Dan , Du Liangui
Published: March 2015

Shale gas and shale oil are the typical ones of unconventional reservoirs in the past decade. Some research studies focused on the effect of porous media on the dew point of gas condensate and bubble point of crude oil systems in terms of experimental and theoretical work. They reached to the contradictory conclusions. Therefore, it is of great importance to develop an effective method to predict the phase behavior of shale gas and shale oil in porous media and investigate the effect of some factors on the saturation pressures of shale gas and shale oil in unconventional reservoirs.

In this work, by taking into account the effect of capillarity on saturation pressures of gas condensate and crude oil systems, the theoretical model has been developed to predict the phase behavior of shale gas and shale oil in unconventional reservoirs. The Parachor model is applied to determine the interfacial tension of crude oil and gas condensate. Some case studies were completed to address the effect of porous media on the phase behavior of reservoir fluids. The effect tendency of some properties of porous media on the dew or bubble point of reservoir fluid is discussed in this paper.
Shallow Gas Overburden Characterisation and Full Wavefield Modelling for Gas Clouds Imaging
Authors: Ang C.T. , Othman H. , Zahir M.H. , Adnan A.G. , Ghazali A.R.
Published: March 2015

Imaging complex subsurface like the gas clouds has always been challenging. Gas clouds are gas accumulation, trapped as an overburden that lowers P-wave velocities (Vp) and frequencies, disrupting transmitted energy and obscures events beneath it. Attenuation of seismic amplitude due to multiple scattering in thin layering of heterogeneous media was first reported by Anstey (1971). A nonlinear full waveform redatuming method proposed by Ghazali (2011) utilized multiple scattering phenomena which described the overburden as complex scattering and translated it to a transmission correction operator. Since it is a nonlinear full waveform inversion (FWI) method, it is important to characterize the rock properties in the gas clouds to identify factors that caused the formation of shallow overburden and help to constraint non-linear inversion results.
Recent Technology Developments in Surfactants and Polymers for Enhanced Oil Recovery
Authors: Lu Jun , Liyanage Pathma Jith , Solairaj Sriram , Adkins Stephanie , Arachchilage Gayani Pinnawala , Kim Do Hoon , Britton Christopher , Weerasooriya Upali , Pope Gary A.
Published: March 2015

Several classes of new surfactants have recently been tested for enhanced oil recovery. These new surfactants were needed for oil field applications under reservoir conditions that made it difficult or impossible to find conventional surfactants with the desired behavior such as ultra-low interfacial tension, aqueous stability, thermal stability at high temperature, low retention, tolerance to high salinity and so forth. We illustrate results for several of these new surfactants and discuss under what conditions they are suitable, how we developed formulations using them and some of the general principles that can be applied to future applications. A common theme of this development is the need for surfactants with large hydrophobes (carbon numbers above 18) even for some light oils. A second common theme is the advantages and flexibility of propylene oxide and ethylene oxide linkages between these large hydrophobes and the sulfate or carboxylate end group. A third common theme is the advantages of highly branched hydrophobes regardless of the other characteristics of the surfactant structure help prevent undesirable viscous phases. Finally, a fourth common theme is the advantages of using surfactant mixtures with diverse structures and sizes. These common elements enable us find surfactant formulations that are highly effective and that can be made from available feedstocks at reasonable cost.
Solid Deposition in Gas Turbines of a Cogeneration Plant, Sumatra, Indonesia, Mechanism and Remediation
Authors: Hwang R. , Iwamoto J. , Coughlan P. , Kumboro D.
Published: March 2015

A rapid build up of solid deposits occurred in the fuel system of gas turbines of the Duri Field Cogen plant and forced to shut down the plant frequently, which resulted in a great reduction in both electric power and steam output and hence curtailed tremendously the field production of heavy oil. A comprehensive study of the fuel gas delivery system and fuel gas quality was undertaken to determine the root cause of solid deposition. The results of the study show that the pale yellowish solids recovered from the fuel system are mixtures of elemental sulfur and wax. Both elemental sulfur and wax were derived from the fuel gas delivered to the plant where they were detected in the gas at trace levels (sub ppm). The occurrence of sulfur and wax deposition was somewhat surprising as the routine monitoring of the gas showed their levels were well within operation specifications all the time. Interpretation of composition data of numerous gas samples and solid deposits combined with operation conditions of gas turbines and gas phase chemistry provided insights of the solid deposition process. The problem was caused by the significant pressure drop encountered in the fuel gas delivery system of the turbines, which induced a measurable temperature drop and the associated phase changes of elemental sulfur and wax hydrocarbons from gas phase to condense phase leading to their deposition and turbine plugging. A remediation measure was developed and implemented.
A New Model to Predict Average Pressure Difference of Liquid Droplet in Gas Well
Authors: Hai-Quan Zhong , Zhong-Neng Liu , Tong Liu , Kai Liang , Yong Ren
Published: March 2015

The distribution of droplet surface pressure is uneven under the action of high velocity gas streams in gas wells, and there exists a pressure difference which leads to droplet deformation before and after the droplet. Moreover, it affects the critical liquid carrying rate. The pressure difference prediction model must be determined, because of the existing one lacking theoretical basis. Based on the droplet surface pressure distribution in high velocity gas streams, a new model is established to predict the average differential pressure of droplets. Compared with the new differential pressure prediction results, the existing pressure difference prediction results overvalued by 46.0%.This article also improves four gas-well critical liquid carrying models using the proposed pressure difference prediction model, and compares with the original one. The result indicates that the critical velocity of the original models is under valued by 10% or so, due to the overestimate to the pressure difference.
Research and Application of Fire-Flooding Technologies in Post-Steam Injected Heavy Oil Reservoir
Authors: Changfeng Xi , Wenlong Guan , Jihong Huang
Published: March 2015

As fire-flooding has strong adaptability to develop the reservoir, it can be considered as a follow-up EOR technology of the low economic profit and high oil recovery reservoirs flooded by water or steam. Because of the complicated secondary water and steam channels, fire-flooding in post-steam-injected reservoir is far different from that in original reservoir. In this paper, the mechanism and problems associated with development engineering of fire-flooding in post-steam-injected heavy oil reservoir was studied systematically by using1D&3D physical simulation systems and reservoir numerical simulator. The temperature of combustion zone decreased and high-temperature zone enlarged because there existed secondary water formed during steam injection which could absorb and carry heat towards producers out of combustion front during fire flooding, but high saturation of water in layer caused by secondary water had less influence on the quantity of fuel deposit and air consumption. In the process of 3D fire flooding experiments, air override was observed during combustion front moving forward and resulted in a coke zone in the bottom of layer, and the ultimate recovery factor reached 65%~70% on fact that the saturation of oil within the coke zone was no more than 20%. The flooding model, well pattern, well spacing, and air injection rate was optimized according to the specific property and the existed well pattern in post-steam-injected heavy oil reservoir, and the key techniques of ignition, lifting, and anticorrosion was also selected in the same time. The pilot of fire flooding in H1 block in Xinjiang oil field was carried out since Dec. 2009on the base of these research work, and now the pilot begin to show the better performance. The production oil is about 49t/d, and the water cut is stable below 70%, the air oil ratio is about 2000m3/t, the good performance is gained for this kind of abandoned post-steam-injected heavy oil reservoir.
Oman Large Carbonate Field Production Improvement Through Integrated Well, Reservoir and Facility Management
Authors: Al-Khadhuri S.M. , Al-Harthi M.M. , Alkalbani A.
Published: March 2015

Managing oil fields in the best way possible has always been in the centre of interests for various oil companies. Production maintenance and optimization, deferment minimization, efficient monitoring of well, reservoir & facility performance, cross-function collaboration, and many other related issues, all represent the building blocks of a successful and efficient field management structure. This carbonate field of Petroleum Development of Oman is one of the largest fields in the Sultanate of Oman and has been running for more than four decades, and still contributes. Hence, it is becoming more important than ever to ensure that the field is managed both optimally and efficiently to adequately handle the subsurface complexity, the large stock of wells and facility units, and all other related issues, such as operations, services, human resources, etc.

An integrated Wells, Reservoir and Facility Management has been implemented to create a more focus and discipline with the aim of achieving an efficiently monitored & controlled asset as well as highly synchronised multi-team actions. The integrated management approach involves structured reservoir and field reviews conducted by integrated multi-disciplinary team, structured processes utilising Smart Field concept and Collaborative Work Environment, enabling technology to obtain data, convert data to useful information and take right decision/action at right time. Exception Based Surveillance is deployed via smart tools to closely monitor and optimise wells and facilities in real time.

As a result of the newly introduced management approach, a total of 26 sectors (more than 450 wells) have been collaboratively reviewed, resulting in:Wells book including full details on current status, challenges, potential activities and short term optimisation plan have been updated for all wells. This is considered a major achievement for this cluster of fields, where for the first time 100% wells were being properly reviewed on yearly basis.More than 150 activities have been identified as well optimisation, reinstatement, repair, data gathering and sidetrack. Excellent optimisation gain has been generated and stable production has been achieved.

Proper planning of identified activities and faster implementation resulting in better reservoir monitoring, excellent production, significant deferment reduction and lesser restoration time of failed wells and equipment.
Understanding Tight Oil Reservoir Hydraulic Fracturing Stimulation Using Two Wells Simultaneous Micro Seismic Monitoring Approach
Authors: Xu Y. , Mu L. , Yang X.G. , Zhao W. , Wang X. , Lim T.K. , Li Y.
Published: March 2015

The tight sand oil reservoir found in the Ordos basin is known for its very low porosity and permeability. Almost every well has been stimulated using hydraulic fracturing techniques. The average production for a vertical well is approximately 4–5 tons per day. Among such a large number of fracture jobs, enhanced production after stimulation does not always meet expectations. Since2005, hydraulic fracturing monitoring services have been carried out widely in this field to improve fracture geometry understanding and optimize well placement. With the implementation on-site, real-time hydraulic fracture monitoring, the pumping procedure can be adjusted accordingly based on the mapped microseismic events.

Based on the past hydraulic fracturing monitoring experience in this field, an average microseismic event detectable distance range around 300 m is expected for the case of geophones inside a monitor well. Two parallel horizontal wells were thus drilled at 600m apart. Horizontal section length is around 1,500m for both wells. The original hydraulic fracture plans for each well consisted of 18 stage stimulations, but were subsequently adjusted to 13stages based on real-time hydraulic fracture monitoring results. Three monitoring wells were drilled from toe to heel as shown in Figure 1. These monitor wells will also be used as water injection wells in later secondary recovery processes. So hydraulic fractures generated by the pumping from both horizontal wells are not expected to extend far enough to reach the monitor wells.

With this favorable well layout, simultaneous dual-well hydraulic fracture monitoring was proposed and conducted. In order to obtain the optimized fracturing parameters first, the initial 3 stages of each treatment well was conducted at one stage per well i.e. stimulate well-1 and then move to fracwell-2. Simultaneous hydraulic fracturing began after the initial six stages were completed.
Application of Chemical Tracers for Clean-Up and Production Inflow Monitoring with Onshore Wells in Italy
Authors: Nutricato G. , Repetto C. , D'Amico A. Santi , Oftedal G. , Faevelen E. , Andresen C. , Leung E. , Wikmark V.
Published: March 2015

Chemical tracers have recently been used to identify oil and water production along different intervals in open hole slotted liner completion, compartmentalized with swellable packers. The reservoir is a fractured carbonate brown field containing several sub-areas producing asphaltene and clasts in which chemical inflow tracers have provided greater understanding of characterizing the reservoir and its' well performance in deviated wells. The permanent downhole tracer systems have been successfully applied in two onshore wells in Italy. The principle of this technology is to place a number of unique chemical tracer systems in different compartments along the length of the lower completion with only minor modifications for clean-up and production monitoring. The system releases tracer into the well stream when wetted by the target fluid, oil or water. When wetted by the opposite phase they will remain dormant, meaning no tracers will be released. The application of permanent oil and water tracer systems placed at pre-defined intervals along the production zones of the wells. Upon well start up, oil samples were taken at the surface and were analyzed to identify which zones were effectively contributing to oil and water production. Permanent water tracer systems were installed aiming at detecting the onset of early water breakthrough. After water break-through has occurred, a regular sampling program is performed and samples analyzed to identify the location of water production to understand the water profile evolution over time. Swellable packers have been used to segment the horizontal sections for the purpose of selective zonal stimulation and to optimize future water shut off intervention by treating the offending zones based on tracer detection. This paper will discuss an innovative wireless approach using chemical inflow tracers as the technology enabler with field proven case studies for clean-up verification, identifying where water and oil is flowing, assess stimulation job effectiveness and estimate relative flow contribution between intervals. Lessons learned for future installations will also be discussed.
A Successful Subsalt Exploration Example in the Precaspian Basin
Authors: Wang Zhen , Zheng Junzhang , Luo Man , Wang Yankun
Published: March 2015

M block in eastern margin of Precaspian Basin is the first CNPC 's risk exploration project in Central Asia & Russia, which has been prospected by many companies and no discovery was found. The main exploration difficulties are subsalt trap recognition's trouble caused by salt domes with giant thickness (greater than 1000m) which lead to subsalt target stratum's pull-up and false faults in the Permian and strong heterogeneous reservoir prediction in carbonate reservoir buried near 4000m. Technology was developed based on the difficulties, in the aspect of subsalt structural recognition, fine interpretation by multi-display methods, salt domes' margin identification using boundary detecting technique, time-depth conversion methods of raytracing procedure, forward modeling examining velocity field's precision, vertical seismic profiling (VSP) detecting local structural shape, palaeotectonic restoration analyzing trap's origin, prestack depth migration verifying trap's validation, salt dome's influence was wiped out continuously and strata's real shape was resumed which leads to the increase of drilling success ratio. In the aspect of carbonate reservoir prediction, favorable reservoir zones in Carboniferous strata were outlined based on the study of logging assessment, sequence stratigraphy, sedimentary facies, seismic inversion, fracture and petroleum detection, attribute analysis. At the same time, REI(reservoir evaluation index) and CI(cave index) indexes were initiated, and carbonate reservoir's logging assessment standard in this block was established that improves reservoir prediction's precision. In the aspect of comprehensive evaluation, 3 structural accumulating belts were divided after the study of reservoir types, which are west structural belt, central structural belt and east structural belt. The different belts' play was evaluated synthetically. The main and potential play was pointed out in different belts. The regular patterns about subsalt carbonate accumulating were generalized. Middle ramp region should be break through first is our bulk exploration deployment clue, and a big field with more than a hundred million tons reserves was discovered which is the biggest subaerial discovery since the Kazakhstan being self-governed and guarantees the abundant supply for the Central Asian pipeline.
Initialising Dynamic Reservoir Models for History Matching Using Pre-Production 3D Seismic Data
Authors: Niri Mohammad Emami , Lumley David
Published: March 2015

Stochastic reservoir modeling is a common practice in the energy industry, and is widely used for hydrocarbon reserves estimation, targeting new producer/injector locations, and production profile forecasting with flow simulators. Due to its high spatial coverage, 3D seismic data plays a critical role for defining the reservoir geometry, and for constraining physical property modeling. However, integration of 3D and time-lapse 4D seismic data into the reservoir model history matching process poses a significant challenge due to the frequent mismatch between the initial reservoir model, the reservoir geology, and the pre-production (baseline) seismic. Therefore, a key step in a reservoir performance study is the preconditioning of the initial reservoir model to equally honor both the geological knowledge and the baseline seismic data. In this study, we investigate issues that have a significant impact on the (mis)match of the initial reservoir model with the geological and geophysical data. Specifically, we address the following questions:Which of the common methods to stochastic litho-facies modelling produce reservoir models that best match the baseline 3D seismic data after seismic modelling?How are the results affected by the presence of noise in the observable data, and by the low vertical resolution of seismic data compared to logs?What is the effect of geostatistical variogram parameters on the results?How do these methods perform on object-oriented reservoir models?

The results of this study indicate that a method based on the probability of litho-facies distribution given by P-wave impedance in a stochastic modeling process yields the best match to the reference model, even in the presence of noise in the dataset. The effect of variogram parameters on the seismically-constrained litho-facies modeling process is also demonstrated.