bluuebunny/crossref_metadata_2025 huggingface dataset:
Ultimate Evaluation of the Alkali/Polymer Combination Flooding Pilot Test in XingLongTai Oil Field
Authors: Zhang Jifen , Wang Keliang , He Fengyun , Zhang Fengli
Published: December 2007

A pilot test of alkali/polymer (AP) combination flooding was conducted in the west area of the fault block of XingLongTai oil field, which was a fringe water reservoir with a gas-cap. There are 11 wells in the oil-bearing area which is 2.05 km2. The central well group contains 3 injection wells and 1 production well and has an oil-bearing area of 0.037 km2. The injection of a slug of 0.35PV of AP combination solution (2% NaCO3 + 1000 mg/L Polymer (1175A)) was initiated in January 1995 when the oil recovery was 46.75% (OOIP) and the water cut was 96.1% and finished in February 1997 when subsequent water injection was started. Up to August 1998, the average water cut was decreased from 98.0% (prior to AP injection) to 93.5% and the oil recovery was increased by 1.98% (OOIP) for the whole pilot area. The water cut was decreased from 98.0% (prior to AP injection) to 85.6% and the oil recovery was increased by 18.5% for the central well group. Numerical simulation was performed and forecasted using the modified UTCHEM (University of Texas Chemical Flood Simulator). The calculation has shown that AP combination flooding can give a much higher oil recovery than water flooding. The ultimate oil recovery by AP combination flooding for the whole pilot area is 50.1% and 147 tons oil can be produced with one ton polymer. Because the pilot area is of a small scale and the initial invest is larger, the economic benefit is not good enough, but the AP combination flooding does be an effective way to enhance oil recovery after water flooding. It is especially true if the target field is of a larger scale. The influence of alkaline loss on EOR, the effect of AP combination system on sweep efficiency and the causes of formation damage are also studied in this paper.
Field Tests of Polymer Flooding in Relative Homogeneous Thick Reservoir
Authors: xue Jiafeng , Liu Xincang , Yuan Tao , Xu Dianping , Ren Wenhua
Published: December 2007

After the success of polymer flooding field tests in the north of Daqing oil field, commercial applications have been conducting, and remarkable technical and economic results have been obtained. In contrast to north area of oil field, XF has characteristics of low permeability differences, lower heterogeneity, lighter oil, and higher recovery by water flooding. In the late developing period of such high water-bearing layers, in order to study results of polymer flooding, polymer flooding field test has been conducted in the central part of Xing-Five area of south of oil field.

The pilot area is composed of 4 anti-five point well patterns which consists of 4 injectors, 9 producers. The distance between injector and producer is 200m, the total area is 0.31km2. This test be gins in 9,1995, cumulative polymer injection volume has reached 748.8mg/L PV by the end of 2,1999. Central producer in pilot area begins to respond when 128mg/L• PV polymer is injected, water cut drops to the minimum of 46.9%; compared with water cut of water flooding, it has decrease by 49.1%. Up to now, cumulative oil production has reached 2.83×104t, cumulative oil increase is 2.07×104t, that is equivalent to an incremental recovery of 13.6%OOIP.

Performance characteristics of field test differ from the north, which reflects in terms of late producers response in the south, late polymer production, low concentration of producing polymer at the same polymer injection volume. It can mainly attribute to relative weak heterogeneity in oil reservoir, relative uniform propagation of polymer, and enlarged swept volume.

Results of field tests show polymer flooding is economically and technically feasible in the relative homogeneous thick reservoir.
Rheology and Stability of IOR Produced Liquid in Daqing Oilfield
Authors: Di Wu , Guangzhi Ai , Yan Chen , Lihua Han , Sen Lin , Xiangchun Meng , Huicheng Liang
Published: December 2007

Rheology and stability of some polymer flooding and ASP (alkaline, surfactant, polymer) flooding produced liquid were studied in this work. Rheology of the produced water plays an important role in the stability of polymer flooding and ASP flooding produced liquid. The stabilizing effect of residual polyacrylamide in produced water on o/w emulsion depends mainly on its influence on the bulk rheology of produced water, i.e. the viscosity and elasticity modulus of the water phase.
Using New Advances in LWD technology for Geosteering and Geologic Modeling
Authors: Efnik M. S. , Hamawi M. , Al Shamri A. , Madjidi A. , Shade C.
Published: December 2007

In this paper, a Middle East field example is shown to illustrate the application of new advances in Logging While Drilling measurements. In addition to standard two mega-hertz multi-depth resistivity, neutron and gamma ray LWD measurements, azimuthal density and photoelectric factor (Pef) measurements were recorded. The real-time and recorded mode applications of azimuthal density and Pef are discussed in this paper.

Conventional LWD density measurements are circumferentially averaged. This technique will smear the density output at bed boundaries, especially in horizontal wells where the bed's relative angle to the well bore is high. Information from azimuthally acquired quadrant density measurements can be used to clearly detect and evaluate bed boundaries in deviated and horizontal holes. In this paper, it is shown how up and bottom densities are used to accurately locate bed boundaries and other geological features such as faults. For geosteering purposes, up and bottom density displacement was able to show if the bed was being entered from the top or bottom of the well bore. It was also possible to estimate structural dip in real-time.

Sixteen azimuthal density and sixteen azimuthal Pef sectors were recorded in downhole memory. Once these LWD data were retrieved from the BHA memory and image processing and image orientation was done, structural features such as fault, bed boundaries and formation heterogeneities were identified. True dip was computed from the density image. The compilation of this information allowed further evaluation of the geologic model of the carbonate gas-bearing reservoir.
Production Performance of Multilateral Wells
Authors: El-Sayed Abdel-Alim H. , Amro Mohammed M.
Published: December 2007

Advances in drilling and completion techniques have allowed drainage of reservoirs via tile use of multi-lateral well arrangements in a variety of configurations. The most important aspects to consider regarding the application of multi-lateral wells are the potential cost benefits and potential risks of utilizing the technology. Difficulties exist in predicting the performance of multi-lateral well arrangements. Many of the performance prediction difficulties are being addressed through different projects.

This paper presents detailed equations to be used for calculating production rate of multi lateral holes both planner and stacked. It discusses the factors affecting the production rate in comparison to a horizontal well. Also, the paper introduces a proposed reservoir and calculates the productivity of that reservoir.
T.R.A.M.S. – A New Standard for Rig Audit Inspection, Management and Sharing
Authors: Thomson Ian W. , Hay Douglas G.
Published: December 2007

Independent rig inspections or audits are widespread within the industry for a number of reasons. They help assure the contracting operator that costly down time is minimised but, more importantly, that the unit is ultimately safe for operations. Major problems exist with current systems. There is a lack of a standard and information is often outdated before the audit report is delivered to the client. The T.R.A.M.S. system has been designed to allow strategic planning, management and implementation of the drilling unit inspection. All historical information is held within a database, which is organised to encourage the sharing of this information across the industry via the World Wide Web. The database is updated with advancement reports allowing details to be followed as the audit progresses.
Blow out Occurrence Caused by Annular Gas Flow after Cementing
Authors: Kadry Khaled
Published: December 2007

Recently Pliocene and Miocene gas discoveries in offshore Mediterranean were achieved. Octopus complex structure is one of the shallow structures that exhibits a well pronounced rollover phenomena where multi bright spots (targets) are present on its crystal part. The well OCTOPUS # 1 DIR is proposed in portfouad development lease to check the potentiality of the Pliocene and Miocene sequence.

The paper discusses the blow out occurrence in said well, after the 2nd stage has been cemented and during final cut 9"5/8 casing. The 9"5/8 casing was set to cover all the high pressure interval where the maximum pore pressure is expected to be (1.75 kg/cm2/10m). And also discusses why the well stopped blowing out after 3 HRS by it self, the damage which has been happened due to cement blowing out, the operation done to replace the damaged well head and BOP stack to rescue the well. And will be discusses also the operations done to resume the drilling operations, some of these operations include, recording TDT - TEMP. Log to establish possible gas pockets trapped behind the casing, recording USIT to identify bridging, gas bucket, and fluid type behind casing. The paper discusses also annular gas migration, and the operation done to investigate and find out the reasons, which contribute to create this type of problem, and the preventive methods recommended avoiding this type of problem. Some of these methods include, adjusting cement column height, adjusting slurry thickening time, applied surface pressure on the annulus during W.O.C. increase annular mud density prior cement job, add gas block to the cement slurry, increase cement slurry mix fluid density, predicts annular gas migration by graph.
Cementing under Extreme Conditions of High Pressure and High Temperature
Authors: Shaheen Mansour , Schulz Jo , Haddad Gaby S. , Helou Husam
Published: December 2007

Wells are classified as High Pressure/High Temperature (HPHT) when BHT (Bottom Hole Temperature) exceeds 250°F (121°C).

Although cementing of all wells is very important and should follow a certain engineering methodology to ensure success, there are some differences related to cementing conditions and the consequences of failures of HPHT wells as compared to normal wells. This paper reviews those differences along with the specific methodology to design, execute and evaluate cementing operations in HPHT wells.

Success factors, such as accurate well data, BHT prediction, optimized fluids and job execution criteria are discussed.

Tools utilized to optimize factors affecting cementing HPHT wells are presented, such as temperature simulator, job design simulator, American Petroleum Institute (API) and specific laboratory testing, Right-Angle-Set cement slurry, mud removal, mixing energy, on-site QC (Quality Control) checks, contingency planning and post-job proper evaluation.
The Charco Redondo Steam Flood Pilot -Reservoir Monitoring Operations
Authors: Widmyer R.H. , Howard C.E.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

The Charco Redondo steam flood was a fully instrumented pilot conducted to determine heat losses, formation heat content, location of formation and injected fluids with time, and residual oil saturations. The data acquired confirmed the ability to predict heat losses and thermal front predict heat losses and thermal front movement. The oil saturation in the flooded reservoir was reduced to approximately 9%.

Introduction

Thermal recovery methods are used to improve production of heavy viscous crude oils. Steam injection is one method used extensively for both pushpull and throughput flooding pushpull and throughput flooding operations. In either application, prediction of reservoir behavior during prediction of reservoir behavior during steaming is necessary so steam generation requirements and costs can be estimated. The Bellaire Research Laboratories performed a fully instrumented experimental steam flood in the Charco Redondo Field, Zapata County, Texas, to verify methods for estimating these requirements. The primary objectives were to determine primary objectives were to determine (1) radial heat losses from the injection well, (2) vertical heat losses to adjacent formations, (3) movement of the various fluids, and (4) residual oil saturations after the steam flood.

RESERVOIR PROPERTIES

Reservoir properties are itemized in Table 1.

PATTERN PATTERN As shown in Figure 1, a 1.01 ha (2.5 acre) isolated inverted five-spot pattern was selected. Injector No. pattern was selected. Injector No. 111 and Producers No. 112, 113, and 114 were drilled to complete the pattern in conjunction with existing pattern in conjunction with existing Well No. 84. The sides of the square pattern were 100.6 m (330 ft). pattern were 100.6 m (330 ft). PRODUCER AND INJECTOR COMPLETIONS PRODUCER AND INJECTOR COMPLETIONS The producers were completed in 20 cm (7-7/8 in.) holes with 14 cm (5-1/2 in.) O.D. casing cemented in place with high temperature cement.
Recovery of Chuc-A Platform Wells at the Campeche Bay, Mexico
Authors: Rodríguez Arturo G. , Martínez Humberto C.
Published: December 2007

The Chuc-A production platform produced an average of 59,200 BPD until October 24th 1997, in this date a fire happened when installing a separator. This oil volume corresponds to the 43% of the field total production. Once the fire was controlled, the personnel of the Drilling Management and Wells Maintenance proceeded to inspect the area with propose to prepare a plan to control wells.

In this paper the operative program and the developed activities to mend wells are shown, incorporating them to production. The activities have been divided in three stages: a) wells control after damage and change of valves to the production trees damaged by fire, leaving them in safe conditions, b) control of wells for the Chuc-A platform restoration and c) Tubing recovery, cut and change of wellheads and production trees, tubing pipe introduction and new subsuperficial safety valves (SSV), stimulation, production surveys, and beginning of the production. Besides, a list of materials, services, safety equipment, logistic and human resources is included which are necessary for the wells recovery.

To carry out the repair operations of all the wells, a total of 387 days was necessary, with a total cost of 15.7 MMUSD, being the rent of equipment the biggest percentage equal to 54.8%. The costs related to services were equal to 4.6 MMUSD, and the costs of materials reached to 2.5 MMUSD. At the end of the operations the eight flowing wells were incorporated to production with similar flow rates to the original ones.

Between the first and the second stage, the wells were set in production during six months while the necessary materials and services were acquired for the final repair of wells.
Optimization of Gas-Well Completion and Production Practices
Authors: McMullan J. H. , Bassiouni Z.
Published: December 2007

In water drive gas reservoirs, wells can be completed with a long perforated interval and produced at high rates to minimize abandonment pressure and maximize recovery. Alternatively, the perforations can be limited to the top of the productive interval and the well produced at a low rate in an effort to prevent coning which results in high abandonment pressures if the strength of the aquifer is adequate to support reservoir pressure. This study uses a reservoir simulation coning model to evaluate these two conflicting completion and production practices. The impact of completion interval, gas production rate, and reservoir permeability were evaluated.

Ultimate gas recovery was found to be largely insensitive to variations in perforated interval and production rate in high permeability systems. Ultimate water production, however, was found to increase at high gas rates and lengthened perforated intervals. In lower permeability systems, ultimate gas recovery was found to increase significantly as production rates were increased, while ultimate water production was actually observed to fall. Sensitivity analysis of vertical to horizontal permeability ratio, fluid density contrast, relative permeability, and formation dip did not alter these conclusions.

The conclusion that elevated production rates can be expected to have no detrimental impact on ultimate gas recovery suggests that gas rates should be maximized in low water disposal cost situations. This finding favors the completion of an interval sufficiently long to maximize production rate and thereby insure that gas recovery and present value of gas reserves are maximized. In high water disposal cost situations, however, it should be recognized that this strategy might result in elevated water production in high permeability systems.
Production Analysis of Commingled Gas Reservoirs - Case Histories
Authors: Arevalo-Villagran Jorge A. , Wattenbarger Robert A. , El-Banbi Ahmed H.
Published: December 2007

A method to match and forecast production rates for commingled gas wells has been developed. In this paper, the method previously developed by El-Banbi and Wattenbarger1,2, was improved and extended to allow modeling of recompletions and different initial pressures in the layers. This new method is based on a layered model that couples the material balance gas equation with the real gas boundary dominated flow equation for each layer of the multilayer-commingled system.

A spreadsheet-based computer program was developed and used to analyze the production history of commingled wells. The program calculates the individual original gas in place, OGIP, productivity index, Jg, and production rates for each layer. It also forecast the production rates of individual layers and the total well. Bottom-hole flowing pressure, pwf, total gas rate history, gas properties, and initial reservoir pressure for each layer are required.

The parameters OGIP and Jg for each layer are determined by history-matching the total gas rate using a nonlinear optimization procedure. This new method gives excellent results for cases dominated by stabilized flow, with occasional shut-ins and substantial pwf variations. The method calculates back-flow between layers during shut-in periods. Although this method is based on using stabilized flow in history-calibration data, validation against numerical simulation shows that the method can tolerate many transient flow periods caused by variations in producing conditions. Several wells were used in testing this method. Five Mexican wells are included in this paper.
Propped Fracturing in Gas Carbonate Formations in Mexico
Authors: Aguilar-Razo R.
Published: December 2007

Since 1995 Pemex E & P has been using acid fracturing to increase production rates in gas-condensate fields in carbonate formations at the Veracruz Asset. The increase in production from fractured wells is an average of 0.5 MMCFD per well. Trying to enhance the fracturing activities, the Veracruz Multidisciplinary Team made a proposal for a project for the application of propped fractures. The project is part of an internal process named Technology Management Process, PAT per its Spanish acronym, conducted and supported by the Technology and Professional Development Subdirection. In Mexico, all the propped fracturing activities were conducted in sandstone formations, especially in its North border, and hence the importance of this work. The project includes 3 propped fractures in fields Mata Pionche, Mecayucan and Copite. In 1998 the well Mata Pionche 1092 was fractured, but the job suffered a premature screenout after 55% of the proppant mass had been placed in the formation. In spite of the screenout, a net increase of 0.2 MMCFD was achieved, not enough to recover the investment in a short time.

This paper presents a Post-Frac analysis of well Mata Pionche 1092 treatment, independent of the Service Company's report. It was finished 12 months after the treatment to include the production response over a considerable period. This paper includes the causes of such screenout concerns and describes multiple fracture geometry using several tools. Although these tools are used to obtain data differently, they are not used in Mini Frac and main treatment data together. This paper will show that the effective use of the combined analysis is more comprehensive.

It is possible to apply successfully propped fracturing in carbonate formations with some modifications to the perforation program, selection of fracturing fluids and flow efficiency testing to diagnose potential problems.
Producing Rich-Gas-Condensate Reservoirs--Case History and Comparison Between Compositional and Modified Black-Oil Approaches
Authors: El-Banbi Ahmed H. , Forrest J. K. , Fan L. , McCain W. D.
Published: December 2007

This paper presents the results of a full field simulation study for a rich gas condensate reservoir with complex fluid behavior. Unique to this paper is a comparison between Modified Black-Oil (MBO) and compositional simulation in a full field model with water influx. Geological, petrophysical, fluid properties, rock-fluid properties, and well data were used to build two full field simulation models (14-component Equation-of-State, compositional model and 3-component MBO model). More than 14 months of daily gas, oil, and water production and tubing pressure data from 4 wells were matched using the MBO model. The model was then used to forecast production and identify new development locations. Comparison runs between the MBO and the fully compositional models were made. It was found that the two models agreed for the entire simulation above and below the dew point and with water influx from the aquifer. The MBO runs were at least 5 times faster than the most efficient compositional run.

The use of the MBO approach allowed a rapid history match of the field performance and a timely completion of the simulation study. Contrary to the common belief that a compositional simulation approach is needed for modeling near-critical reservoirs, this study shows that a MBO approach can be used instead of a fully compositional approach for modeling depletion and water influx processes in near-critical reservoirs. This approach may result in significant time saving in full field simulation.
Permeability Mapping on Vuggy Core Sample Using Tracer Experiments and Stream-Line Simulations
Authors: Moctezuma-Berthier A. , Fleury M.
Published: December 2007

Carbonate rocks have complex porous structure and conventional approach to characterize two phase flow in the laboratory can be inadequate, especially in vuggy structures. Various laboratory studies indicate that centimeter scale heterogeneities have important effects. An important question is the determination of the 3D permeability map later used in the interpretation of two phase flow experiments.

Our approach is based on the combined use of CT scan 3D porosity maps, NMR relaxometry, tracer experiments and numerical simulations to derive a 3D permeability map consistent with the experimental observations. NMR T2 measurements are used to quantify the average porous volume represented by the vugs while CT scan can reproduce the spatial distribution of porosity at the millimeter scale. The permeability map is mainly deduced by fitting the tracer experiment using 3D numerical simulations where we introduce the CT scan porosity map and where the permeability in each grid cell take only two values, one associated with vugs, and one with the matrix.

The study was performed using a volcanic rock (Andesite) with 22% porosity and low permeability (0.4 mD) to mimic a non fractured vuggy carbonate. The variogram analysis in the flow direction does not indicate a correlation of the porosity map. However, the tracer experiment indicates the existence of a preferential path and the measured flux dispersion behaves as in a layered system (early breakthrough, long tail). For a given volume fraction of vugs (congruent with NMR results), the experiments can be reproduced with numerical simulation by adjusting the permeability contrast between the matrix and vug to 360. The use of a streamline simulator was necessary because of the large number of grid cells used and low numerical dispersion. Finally, miscible displacement experiments using different viscosity fluids are interpreted and discussed using three models considering heterogeneity and viscosity.
Integrated Reservoir Characterisation of a Fractured Carbonate Reservoir
Authors: Guerreiro Luis , Silva Antonio Costa , Alcobia Victor , Soares Amilcar
Published: December 2007

One of the most important issues for the characterisation of a reservoir and the assessment of the fluid flow behaviour is the role of faults, fractures, and micro-fractures. At different scales these reservoir features have a tremendous impact on the reservoir drainage and in the overall productivity of the field1.

Faults can compartmentalise the reservoir into different units and the design of the production plan has to account for that. Fractures can be the main path for fluid flow and can strongly affect the production drive mechanism. Micro-fractures have a significant impact on permeability enhancement and drainage areas. The reservoir model should take into account all these features in order to reproduce the internal reservoir architecture and provide a reliable input for the numerical simulation of the fluid flow.

This paper proposes a methodology for integrated reservoir characterisation incorporating micro-fractures and fault analyses. A case study is presented for the characterisation of the reservoir properties and geometry and for the integration of micro-fractures in the final reservoir model.
Laboratory Monitoring of Surfactant Imbibition Using Computerized Tomography
Authors: Chen H. L. , Lucas L. R. , Nogaret L. A. D. , Yang H. D. , Kenyon D. E.
Published: December 2007

Oil production from fractured reservoirs can occur by spontaneous water imbibition and oil expulsion from the matrix into the fracture network. Injection of dilute surfactant can recover additional oil by lowering water-oil interfacial tension (IFT) or altering rock wettability, thereby enhancing countercurrent movement and accelerating gravity segregation. Modeling of such recovery mechanisms requires knowledge of temporal and spatial fluid distribution within porous media. In this study, dilute surfactant imbibition tests performed for vertically oriented carbonate cores of the Yates field were found to produce additional oil over brine imbibition. Computerized tomography (CT) scans were acquired at times during the imbibition process to quantify spatial fluid movement and saturation distribution, and CT results were in reasonable agreement with material balance information. Imbibition and CT-scan results suggest that capillary force and IFT gradient (Marangoni effect) expedited countercurrent movement in the radial direction within a short period, whereas vertical gravity segregation was responsible for a late-time ultimate recovery. Wettability indices, determined by the U.S. Bureau of Mines centrifuge method, show that dilute surfactants have shifted the wetting characteristic of the Yates rocks toward less oil-wet. A numerical model was developed to simulate the surfactant imbibition experiments. A good agreement between simulated and experimental results was achieved with surfactant diffusion and transitioning of relative permeability and capillary pressure data as a function of IFT and surfactant adsorption. Single and multi-well pilot tests at Yates also demonstrated oil recovery improvement and water-oil-ratio reduction in response to dilute surfactant treatment.
Strategy to Reach Deepwater
Authors: Cruz J. Nieto , Rojas G. Santiago , Hernandez A. Gomez
Published: December 2007

This paper shows how Pemex is looking the future to exploit reserves located in deepwater. Southwest Marine Region has increased its exploratory activities beyond the common water depths with high expectations to start up an important development of potential reserves laying in a huge area of the Gulf of Mexico. It is also analyzed some concepts for deepwater applications and regulations stated by Mexican Government to make operations in this area. Pemex has taken advantage of producing in shallow waters for a long time. However, top management of Pemex is aware of assuming the challenge of taking over in new horizons. As a result, it has been planned to integrate a workteam which includes several specialities focused in a long term training on developing deepwater fields.

Introduction

Recently the oil world has focused its attention on deepwater developments and every time more countries have been entering to the scenary. Countries like Indonesia and Egypt have been making important finds in deepwater acreage, Israel is also going into deepwater with a well drilled in 2555 ft water depth in the Mediterranean Sea, Malaysia has drilled its first exploration well in 2,417 ft water depth. Other countries are trying for deepwater plays, Turkey with Limankoy-1 well in 2,788 ft water depth water, Australia is planning to drill three deep water wells over 4,000 water depth. New Zealand with Waka Nui-1 well, in 4,812 ft water depth. Norway have tried with un unsuccessful well in the Gjallarryggen area in 4,400 ft water depth1. The oil world is moving around deepwater, consequently, technology is evolving, day after day.

Surprising projects have grown up in a joint ventures environment like some state companies are doing in their countries. What is important to do in Pemex to keep up with companies actually working in deepwater is to engage human, material and monetary resources in such ambitious projects like Deepstar, kicked off by Texaco2 in 1992 with the mission of encouraging an industry worldwide cooperative effort focused on developing economically viable, fit-for-purpose deepwater technology. Undoubtedly this mission is supported by a great vision. After having runned four phases, benefits have significantly been increased while more operators are being added to the list. To date 23 oil companies are participating and about 45vendor companies contribute in Regulatory, Flow Assurance, Subsea & Equipment, Vessel, Mooring & Riser, Drilling and Completion, Administration, Reservoir Engineering, and Met Ocean, with cooperative efforts further successful deepwater technologies are expected.

What about Pemex E&P?, how is Pemex E&P doing to keep up with this accelerated worldwide change?. Is it prepared to jump over those spectacular projects in an environment regulated by governmental policies?. Technical gap between traditional ways of working in Pemex and those runned by successful companies working worldwide is huge. There is a big hill to climb to reach the top, so, Pemex has to set the pace to overcome it.
In-Situ Reactive System Stops Lost Circulation and Underground Flow Problems in Several Southern Mexico Wells
Authors: Rueda Francisco , Bonifacio Raúl
Published: December 2007

Over the years, operators have used many different techniques in the attempt to solve lost circulation and underground flow problems. Recently, polymer additives and new sealing methods have been used to combat such problems. However, these additives and techniques require extensive preparation time because they must be incorporated into the mud system. While some of these systems can solve minor problems, most cannot solve severe problems associated with large underground flows, fractures, vugs, or channels in weak formations.

A new, reactive, water-based lost-circulation material (LCM) has been successful in treating lost circulation and underground flows. The success of jobs performed with this material depends on the job technique used and the material's reaction with the drilling mud. This LCM is designed to react with water-and oil-based muds as well as environmental muds. It can help stop loss of drilling and completion fluids. Additionally, it can help increase or restore the integrity of weak formations, extend casing-shoe points, and eliminate intermediate casing strings.

This LCM reacts with drilling mud to create a barrier at the face of the lost-circulation zone. The LCM develops a moldable consistency within approximately 30 seconds of reacting with the mud and forms a ductile, nonbrittle bridge against the opening of the fluid-loss zone. This bridge can conform to wellbore or near-wellbore fractures as they change shape be-cause it only minimally penetrates the formation matrix or fracture. In laboratory tests, the material penetrated samples less than 164 in.

This LCM has been successful in the Rio Nuevo, Sen, Fortuna Nacional, and Luna fields in southern Mexico, preventing the operator from having to plug and abandon the wells. Two case histories are presented in this paper.
Design Index: A Systematic Method of PDC Drill-Bit Selection
Authors: O'Hare Jim , Aigbekaen Osarumwense O. A.
Published: December 2007

Advances in drillbit technology have resulted in suppliers adding a seemingly endless array of features to improve bit performance. There is little standardization between bit designs, so drilling engineers and supervisors are faced with difficult choices when selecting drillbits. This paper outlines the development of a systematic method of PDC bit selection. The system is not an ‘expert system’, but a simple methodology that can be readily adapted by engineers to suit their conditions. A basic geological model is developed for each hole section. Formation strength and drillability are calculated from porosity, sonic travel time, matrix rock velocity, degree of compaction, abrasiveness and hole cleaning requirements. The geological model can be adapted to any area by specifying the main rock types and their percentages in the section to be drilled. If not known, typical properties can be obtained from tables included. Individual well profiles are specified by the percentages of build, drop and holding tangent, and also dogleg severity. Combining the geological model and well profile enables a set of ‘ideal’ bit characteristics to be generated. This ideal bit design is compared with the drillbits proposed by vendors. These are ranked by indices for design, performance and economics. [The Design Index takes into account bit characteristics such as the bit profile, number of blades and cutters, cutter size, junk slot area and backrake.] The selection is based on the bit that provides the closest match to the ‘ideal’ design. The methodology has been geared to fixed cutter PDC bits but is being expanded to include roller cone bits. Although the system was originally developed for extended reach and horizontal wells, it can be applied equally to any type of well.
The Mounds Drill-Cuttings Injection Field Experiment: Final Results and Conclusions
Authors: Moschovidis Zissis , Steiger Ronald , Peterson Richard , Warpinski Norm , Wright Chris , Chesney Ed , Hagan Joe , Abou-Sayed Ahmed , Keck Richard , Frankl Matt , Fleming Carole , Wolhart Steve , McDaniel Buddy , Sinor Allen , Ottesen Steinar , Miller Lynn , Beecher Reid , Dudley John , Zinno Dick , Akhmedov Oktay
Published: December 2007

This paper summarizes the results obtained from a comprehensive, joint-industry field experiment designed to improve the understanding of the mechanics and modeling of the processes involved in the downhole injection of drill cuttings. The project was executed in three phases: drilling of an injection well and two observation wells (Phase 1); conducting more than 20 intermittent cuttings-slurry injections into each of two disposal formations while imaging the created fractures with surface and downhole tiltmeters and downhole accelerometers (Phase 2); and verifying the imaged fracture geometry with comprehensive deviated-well (4) coring and logging programs through the hydraulically fractured intervals (Phase 3).

Drill cuttings disposal by downhole injection is an economic and environmentally friendly solution for oil and gas operations under zero-discharge requirements. Disposal injections have been applied in several areas around the world and at significant depths where they will not interfere with surface and subsurface potable water sources. The critical issue associated with this technology is the assurance that the cuttings are permanently and safely isolated in a cost-effective manner.

The paper presents results that show that intermittent injections (allowing the fracture to close between injections) create multiple fractures within a disposal domain of limited extent. The paper also includes the conclusions of the project and an operational approach to promote the creation of a cuttings disposal domain. The approach introduces fundamental changes in the design of disposal injections, which until recently was based upon the design assumption that a large, single storage fracture was created by cuttings injections.
Predrill Pore Pressure Prediction Using Seismic Data
Authors: Sayers C. M. , Johnson G. M. , Denyer G.
Published: December 2007

An accurate knowledge of formation pore pressure is a key requirement for the safe and economic drilling of deepwater wells. A pre-drill estimate of pore pressure can be obtained from seismic velocities using a velocity to pore pressure transform. However, the velocities used are often not ideal. Seismic velocities used during seismic processing are designed to optimize the stack/migration result, with local fluctuations being smoothed out and the velocity sampling interval usually being too coarse for accurate pore pressure prediction. Various methods of determining seismic interval velocities from prestack seismic data are compared, and a velocity analysis approach suitable for pore pressure prediction is recommended. This is aimed at producing a pre-drill pore pressure cube from 3D seismic data, and uses seismic tomography to obtain an accurate velocity model. Seismic velocities obtained by conventional methods average the velocity over the seismic aperture and are therefore not suitable for pore pressure prediction in the presence of lateral variations, as may arise from the presence of dipping structures, lithology variations, salt layers of various thickness, fault blocks or variations in compaction and pore pressure. Reflection tomography gives improved spatial resolution of the seismic velocity field and thus allows a more reliable pre-drill pore pressure cube to be obtained. The method is used to predict pore pressure for a deep water Gulf of Mexico case study.
Formation Characterization of A Horizontal Well While Drilling: An On-Site Tool
Authors: Samuel G. Robello , Miska Stefan
Published: December 2007

This paper describes a method of predicting formation pore pressure and permeability in a horizontal well during the drilling phase of a well development. Dependable and more accurate information about reservoir parameters such as permeability, pore pressure are indispensable for taking proper well completion decisions at a stage when the formation damage is minimal. In this study, a technique is described which can be used as an onsite tool for the evaluation of formation properties for horizontal wells. Method of analysis is based upon the buildup data collected during a test conducted at various stages of the wellbore penetration in the horizontal section while drilling. Modified well testing theory pertaining to horizontal wells is used for the interpretation of the test results. Examples of using simulated data are provided to demonstrate the practical application of the method. These examples using the proposed approach elaborated in this paper illustrate its practicability and the ease of usage as an onsite tool.
Optimisation of Well Economics By Application of Expandable Tubular Technology
Authors: Owoeye Oladele O. , Aihevba 'Leste. O. , Hartmann R. A. , Ogoke V. C.
Published: December 2007

The installation of over 1000 ft of Expandable Sand Screen in a horizontal well has presented the most technically challenging application of the Expandable Tubular Technology (ETT) to date. With increasing emphasis on well economics in the current uncertain oil price regime, the optimization of well configurations, reduction of well construction costs, increase in well productivity and reduction in life cycle well maintenance expenses becomes critical to achieving business success.

The paper presents the deployment of ETT, as an Expandable Sand Screen, in an application that impacts on all three economic factors; well costs, well productivity and life cycle well operating expenditure; positively in a single installation. It addresses numerous drilling, completion and productivity challenges to deliver the optimum drain hole (increased productivity) from a slimmer well (reduced well construction costs) with down-hole equipment that needs minimal re-entries and remedies, (reduced operating expenditure).

With a vision to improve production in SPDC by 60% in the short term and by over 200% (to 2.5 MMbopd) by the year 2010, most new wells are completed horizontally with minimum potentials of 3000 bopd. The application of ESS in horizontal well was a novel challenge, with history of only four installations, the most challenging being the deployment of some 240ft of ESS in a 61° deviated well.

This paper reviews the economic and technical justification for the deployment of the longest and first horizontal application of ESS in the World in Imo River 63 (Ex-SMTQ-5). It emphasizes on the planning, project management, risk assessment, and critical engineering considerations applied to assess the technical feasibility of deploying ESS in a horizontal well.

The paper concludes with the highlights of the execution phase, ESS handling procedure, success, problems and recommendations from the field trial.
Development and Testing of Insulated Drillpipe
Authors: Finger J. T. , Jacobson R. D. , Champness A. T.
Published: December 2007

The Geothermal Research Department at Sandia National Laboratories, in collaboration with Drill Cool Systems, Inc., has worked to develop and test insulated drillpipe (IDP). IDP will allow much cooler drilling fluid to reach the bottom of the hole, making possible the use of downhole motors, electronics, and steering tools that are now unusable in high-temperature formations. Other advantages of cooler fluid include reduced degradation of drilling fluid, longer bit life, and reduced corrosion rates.

The paper describes the theoretical background, laboratory testing, and field testing of IDP. Structural and thermal laboratory testing procedures and results are described. Results are given for a field test in a geothermal well, in which circulating temperatures in IDP are compared with those in conventional drillpipe (CDP) at different flow rates. A brief description of the software used to model wellbore temperature and to calculate sensitivity to IDP design differences is included, along with a comparison of calculated and measured wellbore temperatures in the field test. Analysis of mixed (IDP and CDP) drill strings and discussion of where IDP should be placed in a mixed string are presented.
Lateral Buckling of Pipe with Connectors in Horizontal Wells
Authors: Mitchell R. F.
Published: December 2007

The effect of connectors on pipe buckling has only recently received attention. For non-buckled pipe, Lubinski analyzed the effect of connectors on pipe in tension in a curved borehole and Paslay and Cernocky extended this analysis to pipe in compression. The first analysis of buckled pipe with connectors was done by Mitchell, who developed a three dimensional analysis of helical buckling. These papers indicate that bending stresses are greater due to connector stand-off.

Laterally buckled pipe with connectors is analyzed for the first time in this paper. It presents an analytic solution of the beam-column equations in three-dimensions in a horizontal wellbore with pipe weight. Pipe deflections, contact loads, and bending stresses are determined with explicit formulas. Sag between connectors is calculated so that pipe body contact with the wellbore between connectors can be determined.

Applications include the analysis of bottom hole assemblies, drill pipe, casing, and tubing. The solutions are simple formulas that are suitable for hand calculations.
Emergency Generator Operational Logic for Dynamically Positioned Drilling Rigs working in Ultra-deep Water
Authors: Rankin David , Padel Jacques , Morvan Pierre
Published: December 2007

A typical semisubmersible drilling rig working in water depths of 2000 ft moors using anchors, with thruster assistance to position itself over the work area. Rigs working in deeper water must use dynamic positioning with thrusters only. As the thrusters are electrically powered, any electrical blackout would cause the vessel to drift off station. This emergency situation would be compounded if the drillstring riser were still attached; drilling activity would terminate as the uncontrolled vessel moves away from the wellhead. This incident alone could cost millions of US dollars, with secondary damage possible.

A new rig is available that can work in 8500 ft of water and still remain on station within a specified radius around a given point in defined environmental conditions of wind, current and seastate. Main power generation is provided by six 4400 kW main generators in the pontoons, a location for the main generation that is unique to Sedco Express rig design and is covered by patent application. A seventh main generator on the deck is considered both as an emergency generator and as a service-assist unit under certain operational conditions.

The rig has two service transformers on deck and a third emergency transformer of the same rating topsides, giving significant advantages in the case of service mode failure. Any loss of power to the main high-voltage switchboards initiates a programmable logic controller. The precoded logic opens or closes circuit breakers, immediately switching the topside generator to emergency status to feed the low-voltage emergency switchboard via the emergency transformer, restarting the main generators to recover from the blackout.

Therefore, in effect, no power blackout occurs.

A typical emergency generator run-up time is about 45 seconds, plus human intervention time. On the new rig, approximately 60 seconds are gained restarting operations after a blackout situation occurs as a result of environmental conditions.