bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimal Reservoir Modeling Improves Development Decision Making for a Fractured UK Onshore Oil Field- A Case Study
Authors: Bozorgzadeh M. , Brown J. H. , Bobolecki R. , Meehan D. , Bone K. , Rawlinson A.
Published: July 2010

Optimal technical analysis and pre-development well planning has never been more important in establishing the commercial viability of smaller oil fields. This focus has been exacerbated by recent oil price variation, placing an increased onus on technical teams to make optimal development drilling decisions. This paper outlines a case study of successful technical work undertaken for the further development of the onshore Singleton field, Middle Jurassic carbonate reservoir, UK.

The field was discovered in 1989 and production from the field peaked in mid 1990's at c. 1,000 BOPD. Whilst reservoir porosity is fair to good, with some natural fractures evident, matrix permeabilities tend to be low, resulting in low recovery factors. The field had been producing c. 500 BOPD from 6 wells prior to the operator commencing a development study on the field. The aim of this study was to identify a development program that would significantly increase the reserves, recovery factor, and oil production of the Singleton field.

The Southern Block of the field was high-graded for the study due to its significant STOIIP. This block has been on production since 1990 with three producers online at the time of study. A simulation study was conducted for the area. Through well test analysis and sector modeling fracture and all other key unknown parameters were estimated. A full field model was built based on a 3D geological model and the derived parameters. These parameters were further adjusted to obtain good matching on production and pressure histories. Based on the simulation results, a production well was targeted to the west area of the block. It was predicted that this additional new well would increase the oil recovery factor by 2%. The effect of fracturing on the oil recovery factor was also investigated with a further increase in recovery factor of c. 2 to 3 % possible based on a range of low to high fracture densities.

A new development well was subsequently drilled based on the modeling results. This well came in on prognosis and encountered porous hydrocarbon bearing reservoir section with minor fracture development. The initial well performance has been close to that predicted by the simulation model, with rates and initial reservoir pressure matching the non-fractured simulation prediction case. The simulation modeling helped to improve the geological understanding of the fracture network present in the field. As the well results have demonstrated the viability of the modeling; a number of further development well locations are currently under review to continue the further development of the Singleton oilfield.
Development Planning for Multiple Fields Consisting of Stacked Sands and Containing Multiple Fluids, Jenein Sud, Tunisia
Authors: MANTATZIS Konstantinos , BOISSEAU Yannick , STECKHAN Jan , TORRES Pablo , CLEMENS Torsten
Published: July 2010

The Jenein Sud area is located in the south of Tunisia about 350 km from the Mediterranean Sea. Five successful wells have been drilled in the area and proved that structures containing various fluids are present and can be produced at economic rates.

In this paper, the main challenges encountered in the area and how they were tackled is described.

Pethrophysical parameters: Owing to diagenetic processes such as chloritisation, siderite cementation and quartz overgrowth, the porosity to permeability relationship is diffuse and cannot be consider for permeability estimation. Therefore, all available petrophysical datasets were integrated and clustered by using an appropriate rock typing concept, reflecting the influence of pore geometries on flow and storage.

Sand distribution: Sand layers could not be correlated laterally due to the prograding environment encountered and the large distance between the drilled wells. To capture the uncertainties, a multitude of geological models was created, integrating available seismic data, outcrop studies and trends apparent from regional geology.

Fluids: The individual structures consist of a large number of stacked sands. The fluids in the sands vary from dry gas to volatile oil. All the sands have individual hydrocarbon/water contacts. To determine the fluid composition of the layers and overall performance, MDT samples were taken from the sands and several production tests were performed. An overall Equation Of State model was used to describe the comingling of individual sand layers and to optimise the surface facility design.

Small scale structures: To appraise the area, wells have been drilled in individual structures rather than appraisal wells into selected structures. The wells are used to prove sufficient hydrocarbons and the composition of the hydrocarbons. This information was used to select an appropriate surface facility design capable of handling the fluids and to optimise the production strategy of the area.
EOR: Current Status and Opportunities
Authors: Manrique E. , Thomas C. , Ravikiran R. , Izadi M. , Lantz M. , Romero J. , Alvarado V.
Published: July 2010

A considerable portion of current world oil production comes from mature fields and the rate of replacement of the produced reserves by new discoveries has been declining steadily over the last few decades. To meet the growing need for economical energy throughout the world, the recoverable oil resources in known reservoirs that can be produced economically by applying advanced IOR and EOR technologies will play a key role in meeting the energy demand in years to come.

This paper presents a comprehensive review of EOR projects. Specifically, the paper presents an overview of EOR field projects by reservoir lithology (sandstone, carbonate, and turbidite formations) and offshore versus onshore fields. More than 1,500 field projects are reviewed and summarized to evaluate feasibility of EOR technologies. Another area of growing interest is the combination of near-well-bore and in-depth conformance technologies with chemical EOR technologies such as SP and ASP. However, these are in early stages of evaluation. Examples of numerical simulations combining chemical conformance and EOR technologies are presented showing the potential of this recovery strategy in waterflooded reservoirs. Impacts of carbon capture cost and volatility of oil and carbon-credit markets on CO2-EOR projects based on anthropogenic sources is also addressed.

Based on this review, it is evident that thermal and chemical EOR projects dominate in sandstone formations while gas and water-based recovery methods dominate carbonate, turbidite, and offshore fields. The review also shows the growing trend of CO2 (from natural sources), high-pressure air injection (HPAI), and chemical flooding including in-depth conformance field projects in the U.S. and abroad.

CO2-EOR / sequestration in offshore fields and chemical EOR processes offshore (e.g., polymer-based methods) and onshore, including heavy crude oil reservoirs, are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. The critical review will help to identify the next challenges and opportunities in EOR. Hybrid schemes combining IOR/EOR as well as CO2-EOR/sequestration can be ranked on the basis of adequate simulation procedures.
Medium-High Permeability, Mature Reservoir Management Study: An Innovative Methodology and Case Study
Authors: Liu Xiantai , Wang Zhonghe Peter , Wang Yanzhong
Published: July 2010

Field-wide flow patterns for the 25-year waterflood production history of the medium-high permeability Gudong field, China have been carefully studied using a flow-based numerical simulation process. Through a history matching, field-wide streamline patterns and the cu1mulative flow between injector/producer well pairs can be displayed graphically and quantitatively via well allocation factors. By analyzing the flow pattern or streamline fields (field-wide and locally) for each time step through the reservoir production history, Predominant Streamline Fields (PSF) and Weak Streamline Fields (WSF) can be identified. The PSF can be classified into different levels based on statistically analyzing Strength Index of Streamline Field (SISF), which is a function of both allocation factor and the swept volume of the specific well pair at a given time step. Generally speaking, areas with strong PSF most likely indicate where reservoir channeling occurred at this specific time period, and this channeling is likely to persist until enough change is done. The relative stable WSF zones, with reasonable formation thickness have good potential to be bypassed pay.

To verify the findings above, a dozen conceptual models have been built and tested, and consistent results were found. This dynamic reservoir study processes provided an extra tool for reservoir scale waterflood optimization, well selection for profile modification/water shutoff, and infill drilling.

The Gudong case study indicated that PSF behavior began about 4~ 6 years from the start of water injection. That time period was consistent with a lot of other history data. The findings helped EOR and infill drilling in Gudong field.

Conclusions from this study have led to a better understanding of the displacement mechanisms and the nature-and-man-made dynamic-heterogeneity in the field, which may not be able to obtain otherwise.
Novel Predictive Tool for an Accurate Estimation of the Saturated Water Content of Sour Natural Gases
Authors: Bahadori A. , Vuthaluru H. B. , Jalili J.
Published: July 2010

Natural gas is an important source of primary energy which is saturated with water vapor from the reservoir, through production and processing and is a concern in transmission. Also the water content of sour natural gases is an important parameter in the design of facilities for the natural gas production, transmission, and processing. In this work, an easy-to-use predictive tool which is simpler than current available models and involves a fewer number of parameters, requiring less complicated and shorter computations, is formulated to arrive at an appropriate estimation of the saturated water content of acid gas mixtures up to 69000 kPa. With gases containing CO2, the CO2 must be converted to an "equivalent" H2S concentration. For purposes of this predictive tool, it is assumed that the CO2 will contribute 75% as much water to the gas mixture, on a molar basis, as H2S. The new developed predictive tool works for pressures ranging from 2900 to 69000 kPa and temperatures from 25 to 175°C. The correlation is formulated as a function of temperature and "equivalent" H2S concentration for pressures at 2100, 6900, 14000, 21000, 41000 and 69000 kPa (abs). Simple interpolation formula generalizes the correlation for wide range of pressures. Percent average absolute deviation of the proposed predictive tool is found to be around 2% demonstrating the excellent performance of proposed simple predictive tool and can be of immense practical value for the engineers and scientists to have a quick check on the water content of sour natural gases at various temperatures and pressures without performing any experimental measurements. In particular, gas process engineers would find the proposed approach to be user friendly involving no complex expressions with transparent calculations.
The Mechanism of Pressure Control Problem in High H2S/CO2 Gas Wells
Authors: Zhi Zhang , Jianhong Fu , Yuanhua Lin , Taihe Shi , Hongkang Fan , Bin Xia , Zhang Jincheng
Published: July 2010

Supercritical fluid refers to substancees above its critical temperature and critical pressure. Critical temperature of CO2 is 31.05°C and its critical pressure is 7.38MPa. Critical temperature of H2S is 100.45°C and critical pressure 9.00MPa. The special phase behavior of supercritical state is: Lower viscosity, great density and diffusion coefficient, good mobility, sound solubility and mass transfer behavior and especially sensible to the change of temperature and pressure around critical point. Phase change of supercritical CO2 and H2S will induce serious blowout during the course of drilling and production. In this paper, the reason of well blowout induced by phase change of supercritical CO2 and H2S is discussed proceeded with special phase character by the complex calculation of relevant samples. It is possible that CO2 and H2S in high acidic gas well is in the state of supercritical fluid. Well blowout will occur because the volume of CO2 and H2S in the annulus space is dramatically expanded in annulus space near well head owing to the phase transformation. It is of great importance to discover the kick and to measure the instant annulus flow of drilling fluid during the drilling process of high pressure and acidic gas well.
Efficiency in Cement Jobs for Fresh Water Formations Isolation During Plug and Abandonment in Canadon Seco Field, South Argentina
Authors: Graterol H. J.
Published: July 2010

In the San Jorge Basin, located in South Argentina, Well Plug and Abandonment (P&A) regulations include the guarantee of fresh water formations isolation from once productive formations. Cement Bond and Variable Density Logging (CBL/VDL) are recorded after a squeeze job to confirm cement integrity in the annulus, allowing protecting the most important fresh water formation in the basin: Patagoniano.

Historically, to isolate the Patagoniano multiples of costly squeeze jobs were done to achieve an appropriate result in the CBL/VDL. The main problem from this shallow formation is its high degree of fluid losses, most slurry is lost in these unconsolidated and high-permeability shallow sands (while pumping and during cure). Under this condition costs in the Canadon Seco Field for P&A were exceeded.

To overcome this problem, a review of previous results was done and many flaws were identified in the slurry physical characteristics and the used placement techniques. A new slurry and procedure was selected (after being laboratory tested) to be applied in the field; then a campaign of 14 wells was done using the selected slurry and following a general technique; cost/time reduction was drastic in comparison with previous P&A operations.

This paper presents the whole procedure for achieving these results and also includes details in each phase of testing/design and execution. Geological and mechanical features of the wells are shown, as well as a description of the new technique / slurry (including concepts) and the obtained field results.
Synergetic Use of Cluster Analysis and Artificial Intelligence Techniques to Improve Reservoir Upscaling
Authors: Rezazadeh Mehrdad , Choobary Saeedeh Gharib
Published: July 2010

Upscaling in many cases is essential to reduce the computational time but there is always a disparity between the upscaled model behavior and fine geological model behavior. Up to now there has been an immense effort to reach an upscaling method which is in the most similarity with the fine geological model.

This paper presents a novel implementation of synthesizing statistical tools and intelligent techniques. Statistical tools such as cluster analysis are widely used in order to process multivariate data. It is an integrated approach for petrophysical characterisation of the well data and it can be successfully applied globally to both clastic and carbonate reservoirs with use of logs and core data to define petrofacies. Artificial Neural Networks (ANN) mimics biological information processing mechanisms. They are typically designed to perform a nonlinear mapping from a set of inputs to a set of outputs.

In this paper we used artificial neural network to make modern algorithm for cluster analysis, then by use of this algorithm we make state-of-the-art software for cluster analysis. By this procedure not only computational time is reduced but also the resemblance of upscaled model behavior to the real reservoir geological model is improved.

The procedure and its application in synthesizing cluster analysis and Artificial Neural Networks is demonstrated by a case study.
Strategies for Removal of Formate Brine-Based Drill in Fluid (DIF) Filtercake in Gravel-Packed Completions: A Laboratory Evaluation
Authors: Salgaonkar Lalit , Ali Razien , Danait Achala , Salahudin Sharifudin
Published: July 2010

Formate brines and drilling fluids were primarily developed for high pressure drilling and completion applications. This completion fluid system is now being employed in more benign pressure environments and also to drill and complete formations with specific properties. This was the case where a potassium formate brine with 1.25 specific gravity (S.G.) was specified as the base fluid for the drill-in fluid (DIF) as well as completion brine for several openhole completions requiring gravel packing in offshore Brunei. The DIF used to drill the open hole deposits a protective filtercake on the borehole wall that is typically removed by means of a suitable removal system, enabling undamaged production.

Openhole filtercake breaker systems that are typically employed range from mineral and organic acids, which aggressively attack the filtercake and result in an incomplete cake removal, to ortho-esters, which hydrolyze in the brine and lead to the formation of a delayed acid, which has proven more efficient. The ortho-esters are mixed in the base brine and placed inside the open hole or gravel pack and allowed to react over time.

Formate brines, however, have proven to be poor base fluids for the ortho-esters because of their inherently high pH. A laboratory evaluation was conducted to address this problem. The tests showed that these ortho-ester-based systems, when mixed in a potassium chloride or sodium-bromide brine system, can be employed to break the formate-based DIF filtercake. A chelant-based breaker system, however, provides the most efficient cleanup with the necessary delay. This paper addresses the challenges and details of the laboratory testing performed to arrive at an optimized chelant-based delayed-breaker system in formate brine for removal of formate-based filtercakes. The paper also presents results of the performance of the ortho-ester system.
Mechanism of Well Deviation in Air Drilling and Its Control
Authors: Zhao Zengxin , Gao Deli , Zheng Deshuai
Published: July 2010

Combined with actual air drilling practices and data in western China, mechanical behavior of three different BHA used in actual air drilling was investigated. Bit side force and bit tilt angle of those three BHA both in air drilling and mud drilling were calculated and compared. Analysis results indicated that the bit side force and the bit tilt angle in air drilling is greater than that of in mud drilling due to more deformation of BHA. The fundamental reason of difficulty to control well deviation is because of the great formation anisotropic index and formation dip in air drilling. Some deviation control measures are recommended including the combination of air percussion hammer or air motor and pendulum assembly.
Holistic Automated Workflows for Reservoir and Production Optimization
Authors: Carvajal G. A. , Toro M. , Szatny M. , Robinson G. , Estrada J.
Published: July 2010

The optimization process in the oil industry requires a number of technical applications as well as significant manpower, expertise, and skills to develop robust reservoir and production engineering workflows. Several studies have reported that up to 70% of an engineer's time is spent in gathering, formatting, translating, and parsing data among applications.

Often, engineers are focused on isolated problems and deliver results that are optimized for that element of study. The optimization process frequently involves time-consuming iterations of input variables building output profiles, from which engineers will choose the optimum result. This optimized output data is then taken to the next step in the chain to optimize the subsequent study. These intermittent optimization choices may not deliver suitable input parameters on suboptimal output of the subsequent analyses. Because these sensitivities magnify through the optimization processes, ultimate recovery profiles and field economics are often suboptimal. Even with today's highly integrated databases and enhanced computing power, the traditional working processes will deliver suboptimal outputs.

This paper discusses new toolkits that can model a full chain of application driven data manipulations to assess the ultimate economic effect of engineering decisions such that the best system-wide (holistic) choices can be exploited; the whole of the system is more than the sum of its parts. The holistically optimum result produces the practical natural optimum of the actual operational process. We will demonstrate how holistic optimization processes can greatly enhance workflows for production and reservoir management, fracture design, water conformance, and field development planning.
Design and Performance Research of A Unique Deepwater Cement Slurry
Authors: Wang Chengwen , Wang Ruihe , Bu Yuhuan , Zhou Weidong
Published: July 2010

Deepwater region has been an area of intense interest in recent years, due to the hydrocarbon resources in deepwater areas are very captivating for oil companies. Unfortunately, in deepwater environment, where the water depth is greater than 500 m, faced with some new problems such as low temperature, weak formations, shallow water/gas flow, environmental protection issues and high rig rates of deepwater rigs.

Compared with conventional cementing, deepwater cementing is required to have short thickening time, a fast transition from liquid to solid, rapid development of compressive sthrenth and environmental friendly. Conventional cement slurries and low density cement slurries are usually taking a long time to set and can't allow significant compressive strength development at such low temperature. In addition, conventional cement additives are often environmentally unacceptable subject to more stringent environmental regulations. Therefore, it is stringent to design environmental friendly low density cement slurry to overcoming these challenges during deepwater cementing.

As these deepwater cementing problems are concerned, a new deepwater cement DWC, mainly combining the sulfoaluminate cement and class G oil well cement, was designed for the first time. And, various environmental friendly additives, including cement dispersant, fluid loss control agent and accelerator, were developed. Finally, a unique low density deepwater cement slurry was developed.

Laboratory tests show that the low density slurries has exhibited no free fluid, excellent fluid loss control, right-angle-set, short time of wait-on-time at low temperature, and a shortened transition time of static gel strength. The slurries can be simply prepared, conveniently implemented in field and be composed of environmentally friendly additives. Results presented in this paper should help resolving problems in deepwater cementing.
Advantages of Inflatable Packer Technology for Temporary or Permanent Well Abandonment in the Gulf of Mexico
Authors: Vaucher David , Brooks Robert
Published: July 2010

With so many wells operated in the Gulf of Mexico, one would think that the process of eventually abandoning these wells temporarily (during hurricane season), or permanently plugging and abandoning (P&A) them is by now more routine. Certainly, there are years worth of procedures and case studies on the subject, yet there are always "special cases" that require more specialized planning and equipment. For instance, toppled rigs present the challenge of "kinked" tubing, while other wells have several tubing or casing strings through which a plug must pass before setting in a larger diameter opening.

For these non-routine operations, inflatable packer technology presents several significant advantages: small restriction clearances and high expansion ratios as compared to traditional mechanical bridge plugs. Additionally, inflatable plugs are incredibly versatile in that they can be conveyed to depth using either coil tubing, threaded tubing, even slickline and wireline. Finally, inflatable plugs do cover a wide range of hole conditions (temperature, washouts, etc), and are therefore robust enough for most well decommissioning jobs.

This paper will present the unique advantages of inflatable packer technology in these decommissioning operations and will illustrate these advantages using job examples and case studies. The examples and cases used will be limited to the Gulf of Mexico, yet the advantages of these technologies can be applied to any well worldwide.
Sour Serviceability of Higher-Strength Coiled Tubing: Final Results
Authors: Padron T.
Published: July 2010

As earlier as 1999, the need for industry guidelines regarding the use of coiled tubing (CT) in sour wells was recognized2. Small scale standard NACE tests (i.e. proof ring, C-ring, double cantilever beam, and slow strain rate tests) have been performed to evaluate the behaviour of CT materials in sour environments1,3,4,5. Although these tests evaluate the crack resistance properties of the material in sour conditions, they do not give data regarding the low-cycle fatigue performance of CT after sour exposure that could be used for CT strings management in real operating conditions.

By 2003, uniaxial low-cycle corrosion fatigue tests of short full body CT samples were used to evaluate the sour performance of 70 and 80 grade materials5. These tests, although they considered fatigue performance, were based on uniaxial reversing loads rather than reversing bending strains, which is what occurs in CT operations. In addition to this, the need of high-strength CT materials (i.e. 90 grade and up) in sour wells required additional knowledge regarding their sour performance.

By the end of 2004, a joint industry project (JIP) among ExxonMobil Development Company, Shell Canada Limited and BJ Services Company was initiated to investigate the serviceability of high-strength CT in sour environments, with the main emphasis on the measurement of low-cycle bending-fatigue life after sour exposure using full body CT samples. Some of the early results of this project were included in a previous paper6.

The present paper summarizes more than 4 years of laboratory testing aimed to establish the effect of sour exposure on the low-cycle fatigue life of CT materials. Other aspects related with the possible CT degradation from sour exposure are also included, such as the effect of different sour environments severities, performance of anti-cracking (H2S) inhibitors, effect of pre-fatigue, butt-welds and bias welds performance, and tensile strength integrity. The results have led to changes in the current operating procedures regarding CT strings management and CT material selection criteria for sour service.
Experimental Study on CO2 Monitoring and Saturation with Combined P-wave Velocity and Resistivity
Authors: Kim Jongwook , Xue Ziqiu , Matsuoka Toshifumi
Published: July 2010

As a part of basic studies with the purpose of better understanding to estimate the saturation of stored carbon dioxide (CO2) with seismic velocity and resistivity, laboratory experiment has been conducted to monitor combined P-wave velocity and resistivity simultaneously in porous sandstone during CO2 injection process. Experiments were conducted by simulating the reservoir condition with high temperature and high pressure in depth of about 1000m or more. Supercritical CO2 (10MPa, 40°C) was injected into water-saturated sandstone. The results showed that resistivity increased monotonously throughout the injection period, and P-wave velocity and amplitude decreased drastically after starting injection of supercritical CO2. CO2 saturations estimated by both Resistivity Index (RI) and Gassmann fluid-substitution equations based on P-wave velocity and resistivity were very matched with CO2 saturation from replaced brine in a sample. By comparing velocity-saturation relation with resistivity-saturation relation estimated by Gassmann and RI model, P-wave velocity becomes less sensitive when CO2 saturation is over about 20%, while resistivity kept increasing with increase of CO2 saturation. Resistivity can complement effectively the difficulty of P-wave velocity on quantifying CO2 saturation from suggested equations.
Fiscal Regimes in a Volatile Oil Price Era: What Options Exist for Balancing the Interest of the Resource Country and Investor Company?
Authors: Onyeukwu Humphrey
Published: July 2010

Volatility in oil prices is a reflection of the common characteristic of the commodity-oil. This is linked to a high uncertainty associated with resource development, and the high specificity of investment along the entire energy value chain. Oil price volatility has become a recurring dilemma in an energy market mired in cyclical trends of pricing shocks. The International Energy Agency (IEA) in its World Energy Outlook 2008 predicted an increasing demand at the rate of 1.6%/y on average between 2006 and 2030. As a result, issues of fiscal terms re-negotiations and rent-seeking will shape the relationship between producing countries and investor companies. A major corollary of this instability in oil prices is a renewed battle for rent between host governments and investors. This in effect would engender a shift in balance of the applicable petroleum fiscal regimes.

The challenge of a fiscal policy in a volatile price oil era is ensuring a high share of value is secured for the Government. At the same time, the fiscal policy strives to encourage the exploration of these valuable resources without harming the commercial interest of the oil companies. Price volatility fundamentally alters the sharing formula; it is therefore imperative for a correct balance to be achieved between the competing state interests and the oil companies. The question becomes how equilibrium can be achieved in a petroleum fiscal system design, which guarantees suitable government take and avoids the negative effect of instability and re-negotiation of fiscal terms.

The objective of this paper is to analyse the options available to resource countries in securing appropriate economic rent and safeguard the interest of the investors in the face of pricing volatility. The paper will adopt both analytical and descriptive approaches in articulating these issues.
Corrosion Mitigation - The Corrosion Engineers Options
Authors: Winning I. G. , Taylor Andrew , Ronceray Martin
Published: July 2010

With focus on design of new facilities in hostile environments and re-lifing of aging assets the requirement of corrosion engineers to be able to make the correct decision on the corrosion mitigation methods is key to the continued economical supply of oil and gas. Although many engineers have a broad focus on the options, the techniques available are sometimes disparate and may not be encompassed under one discipline. The development of an overall corrosion mitigation approach and the need to look at total life cycle costs are therefore important for a project to achieve design life or extend the operating life of existing assets. The various subjects including material selection, external and internal corrosion mitigation will be discussed and also how all the possible processes can be bought together into an effective corrosion management system for the long term integrity of the asset.
Water Coning Model for Horizontal Wells in High Mobility Reservoir, West Kuwait
Authors: Al-Enezi K. , Das O. P. , Aslam M. , Bahuguna R. , Latif A.
Published: July 2010

Water coning is a serious problem in horizontal wells in Burgan reservoir of Minagish field located in West Kuwait. The reservoir consists of massive channel sands with active bottom aquifer and having very high permeability in the order of few Darcy. The reservoir contains medium quality crude having viscosity of about 30 cp with mobility ratio of 30 to 40. The localized increase in drawdown at sand-face due to high liquid production rate results in early water breakthrough in most of the horizontal wells, even with high stand off from OWC (Oil Water Contact). After water breakthrough the water cut in the wells starts increasing strictly, resulting in by passed oil region below horizontal well. As producing water-oil ratio starts increasing, the operating cost of the well and oil production cost starts rising significantly. In one of the horizontal well of Burgan reservoir, the water cut increased to 90% over a very short period of production and the water cone could not subside even after the well was shut-in for almost three years, confirmed by running the water saturation logs in the subject well as well as in the nearby offset wells. The water saturation logs clearly indicates the oil water interface and the extent of water coning.

The paper covers an analytical model developed for horizontal well to predict the critical drawdown, critical production rate, extent of water coning, time for water breakthrough and shut-in time required to subside the cone for very high mobility Burgan reservoir. The predicted results are in agreement with the actual well performance and production logging results.

The detailed coning study and model presented in this paper have assisted in planning the advanced completion techniques like Inflow Control Device (ICD) and intelligent multilateral wells with ICD, ICV (Inflow Control Valve) completions to address the severe water coning problems. This allows uniform depletion of reservoir below the horizontal wells for facilitating the steady water-oil interface upward movement below the wellbore. Also the horizontal wells will be placed at optimum distance from the OWC to maximize oil recovery and minimizing the risk of by passed oil.
In Situ Upgrading Extra-heavy Oil by Catalytic Aquathermolysis Treatment Using a New Catalyst based Anamphiphilic Molybdenum Chelate
Authors: Wu Chuan , Lei Guanglun , Yao Chuanjin , Jia Xiaofei
Published: July 2010

The aquathermolysis of Shengli extra-heavy oil during steam stimulation was studied by using anamphiphilic molybdenum chelate-aromatic sulfonic iron as catalyst for the reaction in this papers. The laboratory experiment shows that the viscosity reduction ratio of heavy oil is over 97.15% at 200°C, 24 hr, 0.2 % catalyst solution. The viscosity of upgraded heavy oil is changed from 524.5Pa·s to 14.95mPa·s at 50°C. The chemical and physical properties of heavy oil both before and after reaction were studied by using Fourier transform infrared (FT-IR) spectroscopy, gas chromatography/mass spectrometry (GC-MS), elemental analysis (EL). The percentage of saturate aromatic and H/C increased, and resin, asphalt and S, O, N decreased after the aquathermolysis. The changes of the composition and structure of the heavy oil can lead to the viscosity reduction and improve the quality of heavy oil. It has shown that the mechanism of aquahtermolysis is discussed further. We found the new mechanism of catalyst not only broken C-S bond, but also broken C-O and C-N bonds, and accelerated the reaction of aquathermolysis. The results are very useful for the popularization and application of the new technology for the insitu upgrading of heavy oil by aquathermolysis.
Minimizing Wellbore Damage in a Sandstone Reservoir Using Effective Mud Management Practices
Authors: Mohamed Monir , Rabaa Ali S. , Phillips James E. , Al-Ammari Saleh M.
Published: July 2010

Inducing formation damage in sandstone reservoirs through poor drilling fluids management can negatively affect well productivity. A detailed mud management plan that addresses fluid design and particle size monitoring can help minimize formation damage and improve well productivity. This was demonstrated successfully on 26 wells where the operator implemented an engineered oil-based drill-in fluid (DIF) and a particle size distribution (PSD) analyzer in the field while drilling the reservoir.

The oil-based DIF was formulated with a 70/30 oil/water ratio (OWR) and then treated with a sized calcium carbonate bridging agent to minimize spurt and total fluid loss. The PSD analyzer was used to continuously monitor and maintain optimal PSD values in the DIF. In addition, core samples were examined using a scanning electron microscope (SEM) to determine an average pore size value.

The bridging agent treatment was engineered to help minimize formation damage that results from the invasion of fines, or colloidal solids. Overbalance pressures were also minimized to avoid the risk of differential sticking. The reservoir section was drilled with controlled rates of penetration.

To achieve better bridging results, D90, D50 and D10 particle size distributions were maintained in the programmed range throughout the entire reservoir section. Upon reaching total depth (TD), the bottomhole assembly (BHA) was changed to a reaming assembly and the entire open-hole section was reamed to TD.

After the open hole was deemed in good condition, the well was displaced to a solids-free invert emulsion mud with the same density as the DIF.

A total of 26 wells have been successfully drilled and completed with sand screens using this mud management plan. Testing results indicated minimum skin damage and good stable production rates.
Stuck Coiled-Tubing Recovery Utilizing Surface Equipment and Methods
Authors: Gonzalez O. , Bernat B.
Published: July 2010

Coil Tubing technology grew as an off-shoot of the military needs during World War II. One such need was the requirement to spool continuous lengths of flexible pipeline across the English Channel, and the other post WWII need was to spool out long lengths of communication antenna from submerged submarines. These early advancements laid the ground work for other industries to capitalize on.

It didn't take long for oilfield engineers to figure out the advantages of a continous tubing string for drilling and for working over wells. The need to ‘inject’ coil into a well bore under pressure has resulted in numerous designs, but they all have the basic components of the Injector Head with Guide Arch, Stripper, and a Quad BOP Stack.

As with all oilfield tubulars, the eventuality of having the pipe stuck due to unforeseen circumstances created a satellite industry in removing such stuck tubulars. Many downhole fishing tools have been borrowed from their larger threaded cousins, i.e. tubing, drillpipe and casing strings.

This paper briefly reviews the current techniques of extracting stuck coil tubing strings using downhole intervention, and presents a 12 year old process of surface intervention only, using Surface Resonant Vibratory Energy. Rig up procedures and case histories of this surface technique will be presented along with some engineering theory of the underlying acoustic principles of pipe extraction.
When Should We Run Production Logging Tool?
Authors: Jongkittinarukorn Kittiphong , Kitcharoen Tanyawadee
Published: July 2010

Geology in Gulf of Thailand (GOT) is complicated because of fluvial deposition and multi-stacked reservoirs. The number of sands per well is ranging from three to more than twenty. Under logistic constraints and complex geology, commingled completion strategy is applied to produce these many small gas-condensate reservoirs. Most wells are on primary production without artificial lift. Therefore, water production can cause wells to load up and stop flowing. The gas well loading phenomenon is one of the serious problems that destroy value through production and reserves loss.

To reduce water production, we need to locate the water-producing sand(s) and perform water shut-off (WSO) job(s). Successful water source identification and WSO jobs require good production logging (PL) data. Well condition significantly affects the quality of PL data and WSO decision. On one hand, running PL too late, with high water-gas ratio (WGR), obviously yields insufficient time for WSO action before liquid loading. On the other hand, running PL too early, with low WGR, yields no WSO action. Because of low WGR, it is difficult to clearly identify which sand is the main water source. However, the optimum time for running PLs could not be determined by the available analytical tools.

This study uses a statistical approach, reviewing more than 350 PLs for both oil and gas wells in the GOT. Binary Logistic models are created for prediction of the probability of success (POS) to detect water entry. Based on the well conditions, the optimum time for running memory production logging tools (MPLT) can be estimated with the models. This study found that gas rate, oil rate, water rate, and number of perforated sands significantly affect the POS. Through wellwork prioritization, these models can optimize resource allocation by running MPLT at the right well conditions.
The Effects of Barium Sulphate Saturation Ratio, Calcium and Magnesium on the Inhibition Efficiency: I Phosphonate Scale Inhibitors
Authors: Shaw S. S. , Sorbie K. S. , Boak L. S.
Published: July 2010

Phosphonate scale inhibitors (SIs) are commonly applied for barite scale prevention in oilfields. Their inhibition efficiency (IE) is affected by the barium sulphate saturation ratio (SR) of the brine mix as well as in the presence of divalent cations, Ca2+ and Mg2+. What is less well known is that the precise balance between these factors (SR and Ca2+/Mg2+) can vary significantly for different phosphonate species. This paper presents novel IE experimental results for phosphonate scale inhibitors DETPMP and HMTPMP (pentaphosphonates), OMTHP (hexaphosphonate) and HMDP (tetraphosphonate). Minimum Inhibitor Concentration (MIC) levels for each SI are established using a wide range of brine mixing ratios which changes (i) barite saturation ratio and precipitate mass; (ii) molar ratio of Ca/Mg and (iii) the ionic strength in the brine mix.

The phosphonate SIs were categorised into two types based on their IE/MIC behaviour: Type 1 (e.g. DETPMP and OMTHP) are affected principally by SR and are rather less sensitive to Ca2+/Mg2+and Type 2 (e.g. HMTPMP and HMDP) which are severely affected by brine Ca2+/Mg2+ as well as SR. To demonstrate these effects conclusively, a series of IE experiments are presented with varying brine mix but at a fixed Ca2+/Mg2+ ratio in which the MIC level using both types of phosphonate SI then correlates very well with the barite saturation ratio. In addition, we find the MICs of both types of SI are much lower in the fixed (higher Ca2+/Mg2+ratio) case experiments, compared to the base case – due to the beneficial effect of higher [Ca2+]. The effects observed are important for field application of phosphonate SIs since they show how the various species are sensitive to the changing scaling problem as the %SW increases, in terms of both SR and Ca2+/Mg2+ratio.
The Performance Characteristics of Cr3+ Polymer Gel and Its Application Analysis in Bohai Oilfield
Authors: Lu X. G. , Wang W. , Wang R. J. , Liu Y. G. , Shan J. Ch.
Published: July 2010

The molecular configuration dimension and the flow performance of Cr3+ polymer gel which was formed from partially hydrolyzed polyacrylamide (HPAM) and Cr3+ were studied by making use of the viscosity measurement, core flow performance test and dynamic light scattering (DLS).

The results showed that Cr3+ polymer gels with different molecular structures could be prepared by changing the gelling conditions such as electrolyte concentration of solvent water, Cr3+ or polymer concentration and so on. If electrolyte concentration of solvent water was high while polymer and Cr3+ concentration were low, the cross-linking reaction between polymer molecule and Cr3+ mainly took place among different chains of the same polymer molecule forming Cr3+ polymer gel with the intra-molecular cross-linking structure. Compared with polymer solution at the same concentration, apparent viscosity of intra-molecular cross-linking Cr3+ polymer gel remained almost unchangeable, but the resistance coefficient and the residual resistance coefficient were much higher while the residual resistance coefficient was higher than the resistance coefficient. Moreover, the molecular configuration dimension (Dh) of the gel was only a little bigger than that of polymer solution so that it still had a favorable compatibility with the rock pore of oil reservoir.

As seen from the statistics of the pilot test, Cr3+ polymer gel presented outstanding profile modification as well as oil displacement. The channeling of high permeability zones of oil reservoir were blocked so well, the injection pressure became so high, and thereby there has already being a great effect on enhancing oil recovery and decreasing water cut.
An Integrated Application of Reducing Uncertainties for 3D Pore Pressure Prediction: A Case Study
Authors: Fan Honghai , Zhi Ye , Ji Rongyi
Published: July 2010

Pore pressure is an important geologic parameter in drilling operation, once it influences the definition of mud weight, casing design, drilling cost evaluation, etc. Inaccurate estimates of pore pressure can lead to high costs and unsafe conditions. Basically, the current prediction methods of pore pressure are based on one-dimensional, and can not provide horizontal and the spatial distribution of formation pressure information. While the existing three-dimensional (3D) pore pressure prediction method is not mature enough, and prediction accuracy is not high.

This paper presents an integrated application of reducing uncertainties in order to improve the accuracy of 3D pore pressure prediction and also to give a case study. Firstly, we transform the seismic interval velocities inverted from a 3D calibrated seismic migration volume to pore pressure with an initial pore pressure prediction model, this prediction results clearly have a large range and low accuracy. Next, used seismic data in conjunction with well logging data, mud weight and measured pressure, we can modify and improve model parameters of the initial prediction model. At last, the 3D pore pressure data volume is re-calculated by this new 3D prediction model. This integrated application has been used to improve the pressure prediction results of a petroleum province in the Western of China, and we can get a high precision 3D pore pressure data with this method through analysis and compare.
Fulmar Sandstones, Correcting Some Received Wisdoms in the Greater Kittiwake Area (North Sea)
Authors: Coghlan G. , McRae G.
Published: July 2010

The Fulmar Formation Sandstones in the Central North Sea are a prolific oil and gas play with new developments still being added 35 years after the first discovery in 1975. Typically interpreted as shallow marine, shore-face sands, there is a pronounced halokinetic element to the distribution of the hydrocarbon accumulations.

The Greater Kittiwake Area, GKA, covers several license blocks in quadrant 21. The Kittiwake oil field was developed standalone with a small platform and tanker export with first production in 1990. A satellite field, Mallard, was added in 1998. The fields and surrounding acreage, including several small Fulmar discoveries, were acquired from the original owners in 2003.

Since then Mallard was redeveloped leading to a ten-fold increase in production. Also three Fulmar discoveries were tied-back – Gadwall, Goosander and Grouse. In addition to the production capacity boost, production uptimes were improved and there was sufficient confidence to install an export pipeline. Other satellite discoveries are under consideration as future tie-backs.

There have been surprises along this journey that contradicted pre-development assumptions about Fulmar sandstone reservoirs. A key one relates to the unanticipated strength of the aquifer response in the ‘new’ satellite developments. This flew in the face of received wisdom about Fulmar reservoirs typically not experiencing aquifer drive. It challenges regional expectations about the prerequisite aquifer distribution and size for aquifer drive, also about levels of diagenesis in the water-leg.

In GKA, the Fulmar formation often thins off-structure below seismic resolution - coupled with regional depositional models this is difficult to square with field data from which aquifer drive can be inferred unambiguously. Anticipating where aquifer influx will likely be experienced is important for future developments, as pressure maintenance by waterflood is otherwise required for such tie-backs bringing higher costs and complexity.