bluuebunny/crossref_metadata_2025_split huggingface dataset:
To Improve Benefits by Injection Well Treatment
Authors: Tian Genlin , Tao Cheng , Qu Renwei , He Chang , Deng Jianjiang , Yang Qingjun 
Published: December 2007

Abstract
In this paper, development of a new well treatment method using in situ gelation as well as the pilot test have been presented. The result of the pilot test demonstrated good success in both technical and economic aspects.
For mature oilfields, water cut is normally very high. East part of Shenli oilfield in China is in such category. Water cut of most wells are high than 90%. Some of them are even higher than 95%. That means water flooding efficiency is very lower. Because of employment and economic problems, such oilfield must still keep on operation. In some regions, polymer flooding has been conducted. But it breaks through very quickly. From the break through and other diagnose, it is known that after long time of water flooding, the heterogeneous of the reservoir has been increased, even there are big channels between injection wells and production wells. In order to improve oil recovery in such reservoirs, a injection modification technique has been developed. This method is aimed to shut off big channel near injection wells. By this method, different chemicals were mixed together on the well location. The solution has low viscosity near as injected water. Such solution is pumped into the reservoir by removable pump and close the well 48 hrs for reaction. After reaction, such chemical solution became very strong gel filled in the pores of reservoir. Because during the time of injection, it flew into big channel first. After reaction, big channels has been shut off.
In a pilot test project, 14 injection wells have been treated with this injection modification technique. Reduction of water cut and increase of pressure indicate a good result. It also presented a very good economic benefit for mature oilfield. In this project, the chemical investment was US$. 335,400. Research cost was US$ 96385. Labour cost was US$ 34700.
The total cost was US$ 335422. Increased oil was 34300 Ton. With price of 1250 RMB/t and cost of 443 RMB, the benefit was 24896100 RMB, eg US$ 3 Mill.. From this can be seen that suitable well treatment is very important to mature oilfield. And it can also have obvious benefit.
Behavior of Water Cresting and Production Performance of Horizontal Well in Bottom Water Drive Reservoir: A Scaled Model Study
Authors: Wibowo W. , Permadi P. , Mardisewojo P. , Sukarno P. 
Published: December 2007

Abstract
Although application of horizontal well technology is categorized as a relatively new and expensive but it has been proven more effective and efficient in producing oil. However, the production rate strategy to obtain optimal result has not been well developed due to the difficulties to identify the influence and interaction of forces related to fluid flow mechanisms in reservoir. Particularly for oil reservoir with bottom water drive, the movement of water-oil contact/interface in a reservoir is strongly affected by interaction of the acting forces, such as: viscous force, gravity force and capillary force.
The main objective of this research is to study and investigate the influence of the forces interaction on production performance of the horizontal well producing oil from bottom water drive reservoir. For this purpose, a physical scaled model has been successfully constructed to simulate the prooduction performance. Scaling down and construction of the model are performed by using dimensional analysis.
Results show that the interaction of the forces in the reservoir strongly affects the well production, in which the production performance increases as the ratio of gravity to viscous forces increases for all cases examined. Meanwhile, the changing of capillary force, which was believed by several researchers that it has no pronounced effect to the fluid flow mechanism in the reservoir, shows significant effect to the production performance of the well. The influence of reduced capillary forces in reservoir will enhance the well production performance. Consequently, in term of the ratio of gravity to capillary force, an increase in the ratio tends to improve the oil recovery.
How 50 Million Tons Annual Production Has Been Maintained For 27 Years In Daqing Oilfield ---- A Successful Story
Authors: Yupu Wang , He Liu 
Published: December 2007

Abstract
The paper introduces oil production engineering series for heterogeneous, multilayer sandstone oilfield in the basis of separate zone production in the four development phases including production and stable production. The technologies provide technical means for realizing "Three-changes" of oilfield development, make an important contribution for keeping stable production of 50 million tons for 27 years in heterogeneous, multilayer sandstone oilfield. The development process and several technologies for different development phase are introduced in the paper.
Weighing Investment Decisions Through Project Economics and Optionality
Authors: Biswas Deepankar 
Published: December 2007

Abstract
Uncertainty resolution in recovery driving factors is a crucial issue in oil and gas exploration and exploitation activities. One such application is to select field candidates for development in the midst of several stochastic variables e.g. recoverable reserves, production rates, gas/oil price, discount rates etc. Unfortunately, the cashflows from investments tend to be stretched out in several years. Traditionally, to measure such inherent potential risks, engineering analysis is performed along with project economics. Engineering analysis builds confidence around recovery factors whereas the economic analysis justifies the returns through NPV and IRR computation. One implicit yet critical behavior, however, is often neglected. Investments tend to have embedded flexibilities, i.e. they are not always now or never type, which can be valued as flexible decisions via the theories available for financial options mathematics1,2. This paper investigates the application of financial mathematics to determine viability of a tight gas reservoir as an investment candidate and presents some interesting results dictated by intrinsic optionality.
Real options (RO) have gained increasing popularity in the oil and gas community in the recent past3-6. These applications employ analytic solutions of Black-Scholes type partial differential equation (PDE) available in the literature7-9 which are usually limited to cases of relatively simple payoff structure, exercise strategy, lower dimensions etc. However, most realistic cases, at the very least, will have complex payoff structure e.g. cascading cashflows in the example considered in this paper. Moreover, these options can be exercised anytime during the life of the project i.e. American type options. To accurately and rigorously compute option values in such cases one has to resort to suitable numerical approach to solve the PDE along with appropriate, complex boundary conditions.
In this paper, we prescribe one such technique, namely Implicit Mulitgrid Finite Difference (IMFD) to asses a two well pilot development program. Based on a previous engineering study, stochastic driving factors for the investment are determined. The investment is then crafted in a RO framework. Representative PDE is solved with imposed boundary conditions. Two different scenarios are considered and results discussed. Finally, exercise boundaries are forecasted above which, at a given time in the course of the project life, it is beneficial to exercise the option (in this example drill the development well) instead of waiting for a future exercise.
Hydraulic Flow Units Resolve Reservoir Description Challenges in a Siberian Oil Field
Authors: Svirsky Dmitry , Ryazanov Andrey , Pankov Michael , Corbett Patrick WM , Posysoev Andrey 
Published: December 2007

Abstract
The paper describes results of a petrophysical study aimed to improve reservoir description of a complex oil reservoir located in Western-Siberia, Russia. The K-field was put on production in 1998. The reservoir rocks were deposited in a sand-rich deltaic environment, that implies reasonably good lateral sand bodies continuity. Additionally, no evident continuous faults were seen by 3D seismic survey. However, recent field development has revealed far more complex reservoir compartmentalization and heterogeneity, than it was supposed at the exploration stage. A considerable variation of oil-water contact was encountered and large discrepancy was observed between log predicted and observed well productivity. Additionally core experiments demonstrated poor correlation between porosity and permeability with two orders of magnitude permeability variation at similar porosity values.
The hydraulic flow unit (HFU) approach is used in the present study as an integrating tool for petrophysical description of the reservoir. First, we start from a rock type classification based on core data to pick out major HFU constituting the reservoir. We employ combination of routine and special core analysis data to work out a resulting rock type classification for the studied field. Along with description of the HFU classification, we present the underlying geological reasons which control FZI variation for K-field reservoir. Based on geological and physical background we select relevant logs types related to FZI and propose simple regression approach of for prediction of FZI using gamma-ray and effective porosity log readings. Predictive capabilities of proposed regression approach is compared with more complex statistical techniques and we show that regression approach have reasonable accuracy of predicted FZI comparable to Bayesian inference and artificial neural network methods.
Then we use HFU distributions obtained for each logged well along with classified capillary pressure data for calculation of synthetic water saturation logs and estimation of the free water level (FWL) depth. The estimated FWL data supplemented with seismic information about possible discontinuities and faulting zones are used to update reservoir compartmentalization scheme and to delineate pay zones.
The 3D spatial distribution of the HFU is obtained using geostatistical modeling techniques and integrated into the geological reservoir model to define the porosity-permeability relationships. Additionally, HFU are used in the dynamic reservoir model to assign regions of relative permeability and capillary pressure functions.
The above described simple engineering application of the hydraulic flow units approach allowed us to construct an improved reservoir model and delineate a new probable pay zones, what lead to an increase of estimated oil in place by 70 %.
Keeping Abreast of New Technology Enhances Asset Value - Experience in Romanovskoe Oilfield, Western Siberia
Authors: Nor-Azlan N. , Aker G. H. , Diyashev I. R. , Brovchuk A. V. , Alpatov A. A. 
Published: December 2007

Abstract
Recent years have seen a growing trend towards applying new and advanced technology in the Russian oil and gas business to maximize productivity and enhance assets value. This has led to improved efficiency and greater technical challenges. In large measure, Sibneft owes its predominant position as one of the rapidly growing oil producers in the Russian energy business to its willingness to embrace new technology in order to enhance the value and maximize the productivity of its assets. This paradigm shift has been critical to the company, not only to maintain its leadership among the majors in Russia, but also to be consistent with the country's aggressive strategy to enhance production rapidly to meet local and international energy demand.
This paper focuses on how Sibneft management has been keeping abreast of new technology in order to meet these technical challenges. Romanovskoe oilfield, which is located in the Western Siberian region, is one such field that has been subjected to this proactive philosophy. Due to the heterogeneous characteristics of the reservoir, inefficient thin beds and relative low permeability, specific applications or "right sizing" of technology are crucial to ensure effective exploitation of the field potential. All the wells in the field are either producing via horizontal wells or have been fracture-stimulated since the beginning of their production history.
The critical success factors that emerged from the applications are accurate well placement within the thin oil column (landing the well in the right place and at the right angle), avoiding poor quality reservoir and undulating wellbore for the horizontal wells, and fracture-stimulating the wells in the low productivity regions. The adoption of the strategy has seen substantial increase in the field total production, which is otherwise difficult to achieve without appropriate applications of specific technology. The successes on overall enhance the long-term value of the asset.
Implementation of Remote Start-up Facility on Offshore Installation
Authors: Ismail Saiful Adli , Shukur Maisarah 
Published: December 2007

Abstract
Remote start-up facility is initiated and implemented at some of Petronas Carigali Sdn Bhd (PCSB) offshore installation as one of the initiative to reduce production deferment and optimize resources.
Conventionally, operation's personnel are required to visit the remote platform to perform the local/manual start-up activity whenever the platform has shutdown due to process or other abnormality. The process upset may be originated from the platform itself or due to cascading effect from receiving platform after it has shutdown.
During bad weather, the traveling time by boat to the remote platform is difficult and normally takes longer traveling time. There are also cases where the start-up activity needs to wait on weather when the traveling by boat is not possible due to rough sea.
The delay due to traveling time and further delay during bad weather cause the delay in restarting-up the platform. This start-up delay results in production deferment.
The implementation of the remote start-up facility will enable the operation's personnel to remotely start-up the drilling platform. It is then no longer required to travel to the platform for local/manual start-up activity.
Based on the study conducted, the restart-up delay due to traveling time contributes significantly to the production deferment. Therefore, if the start-up activity can be done from remote i.e. from mother platform or FPSO, then the production deferment can be reduced significantly.
By having remote start-up facility, the total downtime and thus production deferment could be minimized not only during bad weather condition but also during normal weather condition as the travel to the platform is no longer required. This production deferment would accumulate from year to year if not being addressed.
This facility has been implemented on MASA platforms where existing control and safety shutdown systems were modified together with additional instrumentations installed. Only minor modification at relatively marginal cost was required but yet capable of generating relatively significant reduction in deferment.
At MASA platforms, the remote start-up facility is initiated from the FPSO by opening the respective surface safety valves (SSV), Shutdown Valves (SDV) and Choke Valves (CV).
Resistivity Data From A Seismic Survey? An Alternative Approach To Assist Inter-well Water Saturation Mapping
Authors: Widarsono Bambang , Saptono Fakhriyadi 
Published: December 2007

Abstract
Information about spatial distribution of rock true resistivity (Rt) throughout an oil or gas field is always desired. Since seismic survey is the only widespread source that provides information for inter-well locations, considerable efforts have been devoted to extract as much data as possible from it. It is therefore desirable to be able to extract Rt from seismic attributes normally represented by acoustic impedance (AI). This paper presents a field trial of an approach that is basically an application of artificial intelligence (artificial neural network, ANN) on well-log and seismic data based on a proven theoretical relationship that relates Rt to AI. The approach itself, which has been successfully verified through a series of laboratory trials, includes training of the ANN using relevant well-log data, Rt prediction using the trained ANN, and blind tests as means of result validation. An oil field located in East Java is chosen for the trial. It has been shown that there is a certain correlation between log-derived resistivity and log-derived AI. As the approach is applied to map the resistivity and water-saturation, comparisons between conventional/ deterministic water-saturation (Sw) map and the corresponding map resulted from the trial has shown the superiority of the method in presenting inter-well variations in water-saturation. It is also found that the new method has provided a high level of flexibility in interpreting and distributing the inter-well Sw values.
The Use of Integrated Simulation in Decision-making for the Development of Qiaokou Oil-rim Gas Condensate Field
Authors: Guo Xiao , Du Zhimin , Jiang Yiwei , Sun Lei , Bi Jianxia , Liu Xueli 
Published: December 2007

Abstract
The development of complex, deep gas condensate fields with oil ring was once a difficult and uneconomical task to perform. The optimization of conceptual design has now become cost efficient through the use of integrated simulation. This presentation focuses on the integrated study of Qiaokou oil- rim gas condensate field , located in Zhongyuan oil field. The reservoir is of low permeability, low porosity, deep pay and has three fault-isolated produced zones, named Qiao14, Qiao69 and Qiao58 blocks. In 2002, 28 infills were drilled on the basis of adding incremental reservoirs. With the advent of widely available high-accuracy reservoir predicting technology, under-balanced drilling technology and large- scale fracturing technology in Zhongyuan oil field, encouraging factors and results led to a desire to further field- scale development plans. An detailed integrated study of Qiaokou oil-rim gas condensate reservoirs was proposed.
This study involved building a highly detailed earth model to accurately define the geologic framework, and a scaled-up simulation model to optimize the field demonstration project. Based on well log, geologic, and core data, individual-layer data and the faulted structure were mapped. Reservoir behavior of oil-rim gas condensate reservoir is modeled using a 3-D reservoir simulator. The model incorporates a description of the phase behavior of gas and oil rim, well stimulation and compaction in the reservoirs.
The multi-disciplinary demonstration of reservoir evaluation, gas engineering, PVT analysis, numerical simulation, gas production practice, fracture acidizing on Qiaokou oil-rim gas condensate reservoirs has been accomplished by earth scientists, field engineers, and reservoir engineers. An integrated simulation incorporating the demonstrated results of these engineers has been presented to make decisions in Qiaokou oil-rim gas condensate field development.
The study showed the integrated numerical modeling of Qiaokou oil-rim gas condensate reservoirs can be cost effective and SINOPEC has already ratified the further development plan in light of the results of this study. Our conclusions and recommendations will help improve future management and development of Qiaokou oil-rim gas condensate field.
The Investigation of Potential Residual Oil Tapping Technique in the Late Stage of High Water Cut Period in Daqing Oilfield
Authors: Liu He , Yan Jianwen , Hongxue Han , Gang Cao 
Published: December 2007

Abstract
This paper introduces the performance history of the Daqing Oilfield and analyzes the potential for further development.
The residual oil distribution characteristics are analyzed taking the advantage of the core data of Well La8-JP182 and Well Bei1-330-J49. Then the numerical simulation method is used to analyze the recovery ratio, production rate, and the variation of pressure gradient under different production conditions. Finally, the technology of potential tapping of the isolated untabulated reservoirs, tabulated reservoirs, the huge thick reservoirs, and multiple rhythm reservoirs are brought forward in this paper.
Granular Gel-Polymer Treatment Successful in Daqing Oilfield
Authors: Liu He , Han Hongxue , Li Zhuling , Wang Bo 
Published: December 2007

Abstract
Reservoir heterogeneity, along with the oil to water viscosity ratio, cause fingering and water breakthrough along fractures or higher permeability layers of in water flooding oilfield. This in turn decreases the water sweeping volume and water drive effect, making the medium or lower permeability layers poorly productive or even unproductive. As a result, the production wells will be flooded before due or will have a rapidly increased water-cut. Blocking higher permeable layers with chemical reagents along the flow direction of water can efficiently increase the water-affected volume; adjust productive and absorptive sections of the reservoir. Therefore, the water-cut can be decreased, the oil production can be increased, and the objective of stable oil production and lower water-cut can be achieved. This paper presents the techniques used in a field test project conducted at Daqing Oilfield. Granular gel-polymer was used as blocking agent. Economically improved oil production and reduced water-cut were observed.
Numerical Models Help Analyze Lost-Circulation/Flow Events and Frac Gradient Increase to Control an HPHT Well in the East Mediterranean Sea
Authors: Sanad Medhat , Butler Carl , Waheed Arshad , Engelman Bob , Sweatman Ron 
Published: December 2007

Abstract
This paper presents the analysis methods and modeling results from a post-well study of a lost-circulation/flow event in a challenging high-pressure/high-temperature (HPHT) exploration well. The effects of well conditions such as wellbore pressure changes, rock mechanical properties, and geo-pressures are reported. Results from a new lost-circulation, finite element analysis (FEA) model also help explain why various formation-sealing treatment systems (some conventional and others new) failed to reduce the losses into the loss zones. After a new fracture gradient (FG) enhancement squeeze system (FGESS) was implemented, it effectively halted the losses. Full circulation was then re-established to stabilize the well. The well had been losing at an equivalent circulating density (ECD) of 16.4 lbm/gal. Application of the FGESS treatment increased the wellbore pressure containment integrity to sustain an equivalent of 17.0 lbm/gal mud as measured by a formation integrity test (FIT). This remarkable improvement in the apparent or near-wellbore FG (NWFG) or fracture re-initiation pressure (FRIP) was achieved along with several other cost-saving factors.
A new FEA model is also discussed to help show how the FRIP or NWFG was increased by the FGESS treatment and may predict how FGESS treatments can increase the FRIP or NWFG in future wells. This fully 3-D model uses various types of treatment data and well conditions such as wireline log data for formation stresses and rock properties to calculate a FGESS treatment's higher FRIP or NWFG. Upon re-entry of the well 7 months after the successful FGESS treatment, the seal in the loss zones was still holding against HPHT conditions. This sustained seal reduced costs even more and allowed a liner to be set successfully without drilling fluid or cement losses in the reservoir section of the well. The conclusions of the study can help optimize well plans for future wells in the area, which can lead to lower costs for drilling fluids, casing design, cementing, and completion equipment.