bluuebunny/crossref_metadata_2025 huggingface dataset:
Old/New Techniques Translate into Big Savings and Enhanced Stimulation in the Brown Dolomite/Hugoton Fields of Texas and Kansas
Authors: Ely John W. , Martin Michael A. , Duenas Jose J. , Trythall Jerry R.
Published: December 2007

The Hugoton /Brown Dolomite fields have been on production for well over 50 years and are presently producing at very low bottom hole pressures. Early in 2001 a fairly comprehensive study was made evaluating completion procedures with a large emphasis on ways to minimize cost and maximize production. In the study it was determined that virtually every fracturing fluid in the known world had been used in the formation. Additionally there appeared to be little difference in results based upon type of fluid, volume of fluid and proppant and or size of proppant.

Based upon the premise that the majority of the production was coming from natural fractures and that there was little chance of achieving high relative conductivities between these natural fractures and created fractures, a step change was introduced by using smaller proppant. This smaller proppant used in conjunction with fresh water only, would enter and hold natural fractures open. The technique is based upon success in other naturally fractured reservoirs using the "Waterfrac technique".

The technique is extremely simplistic using water with 40/70 sand only in the shallower Texas Panhandle wells with 5.5" casing and water with friction reducer and 40/70 proppant in the slightly deeper Hugoton Kansas wells with 4.5" casing. Early concerns related to watering out or drowning the very low-pressure zones but capillary imbibition allows all of the water to be absorbed by the formation and little or no frac fluid is produced. There are differences in completion techniques between Kansas Hugoton and Texas Panhandle Brown Dolomite relating to open hole versus cased wells and formation water production and these will be discussed separately in the paper.

A large part of the paper will be spent comparing production of these wells with more conventionally completed wells, using large proppant and crosslinked foam fluids. Additionally a review of the success achieved utilizing under balanced horizontal wells is compared to the waterfrac vertical completions.
Transient Pressure Analysis for a Vertical Gas Well Intersected by a Finite-Conductivity Fracture
Authors: Nunez Walter , Tiab Djebbar , Escobar Freddy H.
Published: December 2007

Pressure-transient analysis for gas wells has a great importance in the oil and gas Industry. Transient pressure responses of unfractured and hydraulically fractured gas wells may be affected by non-Darcy flow near the wellbore, such important effect needs to be taken into account when estimating reservoir and well parameters. An additional problem encountered in gas wells test analysis is the presence of the rate-dependent skin, which requires a search for another parameter (non-Darcy flow coefficient).

Several tests are performed in order to measure the deliverability of gas wells and to describe reservoir performance. Such specific tests as flow after flow, isochronal and modified isochronal were initially designed to obtain the absolute open flow potential of a well, however, the use of these tests has been extended to obtain additional information from the reservoir. Drawdown tests are focused in obtaining such data as wellbore storage, reservoir transmissivity, skin factor, flow efficiency and system geometry. Buildup tests lead us to the average pressure of the reservoir, however, proper analysis of buildup test provides values of permeability, wellbore storage and apparent skin factor. Buildup and drawdown tests are currently analyzed using type-curve matching procedures, which involves trial and error and conventional techniques.

Pseudopressure concept, which was used in this study, has shown to provide sufficient engineering accuracy in dealing with gas well test data. This study utilizes characteristic points, intersection and lines found on the pseudopressure and pseudopressure derivative plot to obtain fracture length, fracture conductivity, skin factor and reservoir permeability.

It was found that changing the non-Darcy factor, D, the shape of the pseudo-pressure curve varies from the original gas curve shape at D=0, which implies that an additional skin effect is added at high rates. On the other hand, the pseudopressure derivative curve remains on its original shape, then, in spite of increasing non-Darcy effect factor, D, the pseudopressure derivative curve is not affected by this additional skin effect added to the system because of the non-Darcy flow effect. The interpretation technique was successfully tested with simulated and field examples.
A New Robust Model for Natural Separation Efficiency
Authors: Marquez R. A. , Prado M. G.
Published: December 2007

This paper presents a mechanistic model to predict natural separation efficiency. Based on drift-flux model, a new mathematical formulation was developed to estimate natural separation efficiency. The new model considers the existence of the slip velocity not only in the vertical direction, but also in the radial direction. The new and robust model is a function of important variables such as geometric characteristics of the bottomhole, slip velocity at both vertical and radial direction and the gas and liquid flow rates. Available experimental data was used to obtain a new correlation for the bubble drag radius, as a function of gas flow rate. Predictions of the model have been compared and verified against experimental data, showing good agreement.
Economic Comparisons of Multilateral and Horizontal Wells in Water-Drive Reservoirs
Authors: Rivera Nestor , Jensen Jerry L. , Spivey John P. , Jardon Mike
Published: December 2007

Reservoir studies can help determine what parameters or configurations make multilateral wells (MLs) more economical than single-branch horizontal wells (HWs). We simulated 5 years of production from a water-drive reservoir and evaluated the results, using a range of economic criteria. The reservoir simulator uses a multisegment wellbore model to enable better handling of complex well trajectories and detailed description of pressure losses in the horizontal, building angle, and vertical sections of the well. The study compared Levels 3 and 6 ML junction configurations to HWs. We modeled natural flow applications considering normal gravity oil (20 to 29° API) in a homogeneous reservoir with permeability ranging from 10 to 1,250 md. Detailed well-cost estimates for each configuration included taxes, royalties, and water-handling costs. We found that accounting for friction and hydrostatic pressure losses through all the sections of the well created more realistic models. For the cases we studied, a two-branch ML produces 13% more oil than a HW in highpermeability reservoirs and 80% more oil in low-permeability formations with low viscosity oil (1 cp). In addition, the ML well produces 10 to 15% less water than the HW. The extra production of the ML over the HW increases to more than 50% in low-permeability and higher than 90% in lowpermeability. The ML has a higher net present value—20% or greater—than the HW for all permeabilities. Using a profit-toinvestment ratio, the ML is more attractive than the HW in the lower permeability cases. Results using other economic metrics gave similar results.
Utilizing "Over-Seas" Technology Improves the Cementing Processes in the DJ Basin of Colorado
Authors: Shaefer Mark , Clausen Fred
Published: December 2007

Cementing a liner string from the older Codell wellbores down to the J-Sand formation has been an important project in the DJ Basin for Kerr-McGee. The existing Codell wellbores have been deepened with a liner string because in 1998 the J-Sand well spacing was reduced from 160 acres down to 40 acres. The decrease in the spacing requirements created an infill drilling and deepening program in the DJ Basin. Typical cement volumes for J-Sand deepenings liner strings have been small, requiring 35 sacks of cement. The small cement volumes combined with the high bottom hole temperature (265°F) and narrow casing/hole clearances have made cementing practices difficult to implement for the service companies and operators in the DJ Basin. Traditional cementing practices have resulted in a +/- 10% failure rate in cementing the liner strings. The 10% failure rate and the "gray hair" factor that comes with cementing liners has been overcome with the use of overseas technology. Instead of dry powder cement, a Fluidized Cement Premix (FCP) has been utilized and pumped on more than 100 liner cement jobs with no problems for the service company or operator.

The objective of this paper is to identify and evaluate the benefits derived from switching from the conventional dry slurry to the FCP slurry. The benefits will be shown through the use of a statistical comparison of job success plus cost and a qualitative comparison of cement bond log signatures. The economic benefits will be explored for both the operators and the service company.
Economic Completion Slurries Utilized in Partially Depleted Reservoirs
Authors: Purvis D. L. , Merritt J. W.
Published: December 2007

Cementing production casing in partially depleted reservoirs is a common problem in the Mid-Continent. The industry is continually looking for alternative slurry designs to lower annular pressures during cementing while maintaining the material properties needed for stimulation and zonal isolation. In order to be viable, the resulting technology must decrease density while preserving compressive strength, fluid loss and free water properties of the cement. Cement slurries using foam or hollow spheres are capable of meeting these requirements. The additional equipment and material cost required usually prevent these systems from being economical when mixed between 13.5 and 14 ppg (lb/gal).

Recent technical developments have lead to the creation of slurries weighing 13.8 ppg containing 60% pozzolan and 40% API cement. These economical slurries exhibit mechanical properties comparable to standard API slurries having much higher densities. Laboratory testing and bond logs are presented and compared along with recommended applications.
Ratings Standardization for Production Packers
Authors: Fothergill John
Published: December 2007

Longstanding ambiguity surrounding performance ratings for production packers continues to be a topic of concern, as increasingly demanding completion environments drive more critical product selection processes. Inconsistencies in manufacturer testing methodologies and design validation procedures have previously not supported a quality selection process. Completion engineers, not equipped with a thorough understanding of the nuances of packer performance characteristics under various load conditions, have been dependent upon the technical expertise and good faith of the manufacturer.

This paper gives the completion engineer a working understanding of applied packer performance ratings. The evolution of qualifying testing procedures is discussed, as well as the most recent advancements in the standardization process. Ratings standardization set forth in ISO 14310, establishing both quality control and design validation grades, is described. Completion engineers and other decision makers, as well as salesmen need this information for informed product comparisons and proper matching of product to application.
Remediation of Salt-Impacted Soil and Waste
Authors: Deuel Lloyd E. , Holliday George H.
Published: December 2007

Salt impacted soil and waste remediation imposes one of the most difficult challenges to oil and gas operators, because of the expense and extended treatment time. Additionally, salt impacted land constitutes a fertile litigation target regardless of capability and practical land use. Expensive judgments in Oklahoma and Louisiana are becoming common. It is only a matter of time before similar court actions are brought in other oil and gas provinces. Proper remediation or corrective action avoids or mitigates these judgments. This paper offers practical methods for reducing remediation/re-remediation time and expense associated with produced water releases, production pit closures and spent saline drilling fluid/cuttings remediation.

The paper provides field-tested guidelines for mitigation; treatment, and post closure reconstitution of salt impacted soil and solid wastes. Currently, the technical literature offers little guidance in how to locate, mitigate, treat and reconstitute new or previously treated impacted soil/waste.

Based on our research, we conclude most salt-impacted areas can be treated to regain pre-impact land use capability status. The elapsed remediation time ranges up to 7 years. In severe cases, the operator may elect a long-term (30+ year) passive treatment appoach by planting salt tolerant species (halophytes).

The remediation methods presented in the paper are proven practical by long-term use and observed reconstitution of salt damaged land.
Collaboration in Knowledge Sharing
Authors: Rawdon Jack C.
Published: December 2007

The demand for oil and gas will increase substantially in the next ten to twenty years. The energy industry knows where oil and gas supplies are located, and can meet the demand if the industry promotes the benefits of collaboration in knowledge sharing. The industry will need highly qualified technical communities of practice who can communicate effectively and expand new technologies and best practices.

These key technical community professionals will effectively transfer and promote knowledge sharing among peers to ensure the success of major projects. These knowledge sharing communities of tomorrow will be a key component for corporations to be successful in their quest to protect the health, safety and environmental aspects of their projects. The knowledge sharing community core team business model is instrumental in expanding best practices and delivering recommendations in an easy and effective manner.

Successful corporations will seek to improve and increase their collaborative efforts on a global scale. Those corporations investing the proper time and talent in community business models today will reap the profits of collaboration in knowledge sharing, and secure a successful seat in the global energy arena of tomorrow.
U.S. Natural Gas Market: Recent Dynamics and Future Concerns
Authors: Schubarth S. K. , Byrd A. C. , Wickham J. F.
Published: December 2007

The US Natural Gas Market has moved through some very dynamic events over the past few years1. The fact that ninety-nine percent of all gas consumed in the US comes from the North American Continent plays a large part in the lack of stability in pricing of Natural Gas. The nature of the production stream feeding the demand for gas has changed drastically in the past decade. The potential demand for gas during peak usage periods of each year has changed dramatically and the maturity of the available gas development projects have all led to a greatly different market than ten years ago.

This paper will focus on the three main points of interest; first, the production supply of gas in the US and how the underlying decline rate of produced gas has changed. Second, the root cause of the recent gas price increase and resulting fall. What caused it and how likely is it to occur again. Lastly, What will it take to meet the increasing demand for natural gas into the future?
Overview of Coalbed Methane Best Management Practices and Mitigation Techniques Using Geospatial Techniques
Authors: Arthur J. Daniel , Patton Jason , Richmond Tom
Published: December 2007

During the second half of the 1990's, Coalbed Methane (CBM) production increased dramatically nationwide to represent a significant new source of income and natural gas for many independent and established producers. Matching these soaring production rates during this period were the advancements in Geographical Information Systems (GIS) technologies generating terra-bytes of new data for the oil & gas industry. Coupled to these accelerating initiatives are Sub-Bituminous coal from an outcrop in the Montana Powder River Basin many environmental concerns relating to production wastes and water table depletion of fresh water resources. It is these concerns that have prompted the conceptualization of this project for the development of Best Management Practices (BMP) and mitigation strategies utilizing GIS technologies for efficient environmental protection in conjunction with effective production of CBM. This has been accomplished by developing a framework to take advantage of a combination of investigative field research joined with leading edge GIS technologies for the creation of environmentally characterized regions of study. This paper will provide a summary of CBM BMPs as well as the use of an Internet-Based GIS application for geospatial analysis relative to CBM development and evaluation of various mitigation techniques and best management practices.
Improving the Sulfate Resistance Performance of API cement Class A upon Appropriate Slurry Design
Authors: Morales Marcela , Morris Walter , Criado Marcelo A. , Robles Jorge , Bianchi Gustavo
Published: December 2007

Class A cement has been used for cementing surface casings and shallowwells. API Specification 10A classifies the well cements into three categories, ordinary, moderate and high sulfate resistant, depending primarily on theamount of tricalcium aluminate (C3A) present in the clinker. Cementclass A (ordinary) presents no C 3A restrictions. On the other hand, moderate and high sulfate resistant cements should contain less than 8 and 3 %C3A respectively.

Under certain conditions, sulfate ions will chemically combine withtricalcium aluminate giving rise to an expansive reaction that can cause cementdistress. This process depends on cement permeability and environmenttemperature. Several research studies conducted in this field have proven thatthe degradation process decreases as temperature increases and can becontrolled lowering the cement permeability.

The purpose of this study is to analyze the sulfate attack mechanism atseveral bottom hole conditions in order to ensure an appropriate well isolationdurability performance using cement class A. Specimens prepared with APIcements class A and G were exposed to solutions containing sulfatesconcentrations ranging from 0 to 30000 ppm and temperatures of 89.6 and 183.2°F (32 and 84 °C). The specimen 's length and weight variation was evaluatedperiodically. The presence of expansive phases (ettringite) was detected bymeans of SEM and EDAX analysis. A model to predict the cement degradationprocess due to sulfates attack is proposed.

The cement specimens (A and G) showed no significant expansion during thefirst 240 days of exposure, however growth of secondary ettringite in cementpores was detected by SEM analysis. The sulfate degradation process requires acertain incubation period before the cement pores get completely filled withettringite. The use of pore blocking additives increases the sulfate resistanceof cement class A, ensuring appropriate performance and durability.
Design of High Toughness Cement for Effective Long Lasting Well Isolations
Authors: Morris Walter , Criado Marcelo A. , Robles Jorge , Bianchi Gustavo
Published: December 2007

During the well service life the cement isolation is exposed to extreme conditions that can cause its premature failure. Certain well completion operation as perforating and hydraulic fracturing, the changes in temperature and pressure during secondary recovery or the mechanical stress originated by formation displacements may cause severe damage to the cement isolation.

The mechanical properties (compressive and tensile strength, toughness, Young modulus and Poisson ratio) of different cements were evaluated in order to establish their best service performance. Typical slurry designs were tested focusing the attention on the effect of certain additives such as latex, fibers and other polymers used as fluid loss control or dispersants.

The cement mechanical properties were determined according to ASTM and API standard test methods. The cement toughness was evaluated following the API RP 43 standard for testing well perforators.

The experimental results show that the mechanical properties of cement are strongly dependant on the particular additives used when preparing the slurry. Even when cement with no admixtures presents high compressive strength it also shows a fragile behavior with limited strain and low toughness. The use of latex improves the cement elastic behavior although it does not better its impact resistance. On the other hand, the addition of polymer fibers improves the cement toughness and its elastic behavior. As it was demonstrated by well testing profiles run before and after perforating, the addition of fibers improves the cement performance when exposed to the different events that may damage the isolation during the well service life.
Acoustic Signal Analysis for Sand Detection in Wells with Changing Fluid Profiles
Authors: Allahar I. A.
Published: December 2007

Sand production can be a severe problem in the East Coast oil and gas fields of Trinidad. Geologically young formations in this region exhibit little to no natural cementation forming very weak unconsolidated sandstones that often lead to sand production. With the increasing drive to increase production rates, the accepted draw down limits for these reservoirs may be tested. As a result surface monitoring and early detection of sand production has become extremely important in providing further assurance to mitigating potential incidents due to sand production resulting from excessive draw downs.

For this project, data collected from thirty acoustic sand -detector calibration trials done in three fields offshore East Coast Trinidad, was analysed to investigate the accuracy of the sand detector in predicting sand concentrations in different fluid profiles. From this study, a simple model is being proposed which can predict sand concentration for sand particles ranging between 30 to 120 microns at any given fluid profile using an acoustic sand detector. This model may be used in the absence of a calibration plot and when the flow profile of a well is changing, to accurately predict sand concentration. The results from this project can provide the operator with greater assurance when optimising production rates, especially in wells that have a tendency to produce sand.
Hydrocarbon/Solvent Treatment for Inhibiting Paraffin and Suspending Asphaltenes in Oil Wells
Authors: Campbell Gale J. , Griffin John M.
Published: December 2007

A blend of polymeric hydrocarbons within a solvent solution (HIS-polymer) has been developed (patent pending) that enhances the flow capacity of oil wells adversely effected by (a) high viscosity, (b) tubular and rock matrix plugging due to precipitation of paraffin and asphaltene.

Theoretical mechanisms contributing to observed flow increase following application of HIS-polymer in field conditions include (a) preferential wetting of matrix surfaces by HIS-polymer, (b) reduction of relative permeability to water and increase of relative permeability to oil, (c) stabilizing interfacial tension, (d) generation of heat which disperses paraffin and asphaltenes sufficiently for them to enter flow stream, (e) inhibition of paraffin precipitation, (f) deasphalting heavy crudes through solvent action, (g) dispersing and inhibiting the onset of asphaltene precipitation.

Long-term benefit of treatment (exceeding 9 months) is explained by preference for polymeric hydrocarbon to wet previously water-wet matrix. Verification of same is reported using dual-drop-dual-crystal technique in which a 500 ppm concentration of HIS-polymer was observed to convert both a water-wet quartz and calcite to a polymeric hydrocarbon-wet surface.

Field treatment by bullheading through tubing into formation and over displacing with diesel or lease crude is reported. This treatment was for a 15° API oil in eastern Venezuela and resulted in a three-fold production increase from 104 barrels of oil per day (BOPD); production was sustained for an excess of 60 days. Tripling of production in a west Texas stripper well is also included. The HIS-polymer benefits operators by replacing diluents that have been historically used to decrease pressure of heavy oil laden flowlines.
Gas Flood-Flow Pattern Evaluation: A Successful Interwell Field Study
Authors: Mercado Modesto , Perez Carlos E. , Asadi Mahmoud , Casas David R.
Published: December 2007

A successful reservoir flood depends on a properly designed injection/production pattern. Knowledge of the flow pattern within a reservoir leads to a better design of the injection pattern, which in turn enhances overall recovery. To achieve this goal an interwell tracer program was used to characterize the flow stream within the current injection/production pattern of the central part of the Mesozoic Chiapas-Tapasco Basin. The field includes one injector and four producers. Due to production, the average reservoir pressure fell and approached the dew point at reservoir conditions. Natural gas was injected to maintain reservoir pressure and optimize condensate production. A chemical interwell tracer was also injected to detect and evaluate the magnitude of any communication between the injection and production wells and to track the areal flow pattern within the field. The study was designed for 18 months and commenced in December 2000. The results from the sample analyses provided information on the magnitude of highly permeable channels between the injector and producers as well as flow pattern within the field. Furthermore, the results provided valuable information on breakthrough time, which in turn shall lead to a more efficient gas injection design.
Pore-Level Observation of Gravity Assisted Tertiary Gas-Injection Processes
Authors: Ren W. , Bentsen R. , Cunha L. B.
Published: December 2007

In water drive oil reservoirs, more than half of the initial oil in place is trapped in the water-contacted zone after natural water influx or waterflooding. Gas injection into such reservoirs, with the assistance of gravity, interfacial tension and oil film flow, can cause the displacement of excess water and the redistribution of reservoir fluids in the pore space. As the result of such fluid redistribution, most of the residual oil can be recovered. Moreover, a second water flood following the gas injection can recover the oil in a shorter period of time.

Gravity assisted tertiary gas injection processes include the Double Displacement Process (DDP) and the Second Contact Water Displacement Process (SCWD). The DDP consists of injecting gas into waterflooded oil zones. The SCWD process consists of submitting these gas-flooded zones to a new water displacement process. In this work, the double displacement process (DDP) and the second contact water displacement (SCWD) process were conducted in a transparent sand-pack micromodel, and a pore-level observation was performed to investigate the microscopic mechanisms of the two processes.

Observation of the two processes confirmed that the oil films play a very important role in achieving high recovery efficiencies in the DDP. The oil film was seen clearly. Such observation showed also that oil flowing through oil films and layers was driven not only by its own weight, but also by the increasing volume of the gas. In the SCWD process, trapped gas reduces the possibility of the residual oil being trapped in the center of the pores. Consequently, residual oil can be recovered quickly by a second water flood. Therefore, the SCWD process is suitable to apply in situations where the source of gas is not sufficient, and where the formation has a high irreducible gas saturation.
An Integrated Long-Term Solution for Migratory Fines Damage
Authors: Hibbeler Jeff , Garcia Thomas , Chavez Nelson
Published: December 2007

Mobilization of fines can severely damage a well's productivity and is one of the more costly sources of well damage identified to date. Termed fines migration, the phenomenon is complex but governed largely by mineralogy, permeability, salinity and pH changes as well as drag forces created by flow velocity, turbulence and fluid viscosity1–10.

Over the years various mixtures containing hydrogen fluoride (HF) acid or its precursors have been used to dissolve fines and increase permeability in sandstones. However, it has been noted in considerable prior literature11–21 that these treatments can result in relatively shallow penetration due to the rapid spending of HF. Frequently the treatment is limited to a few inches in the formation beyond the wellbore region and this allows future fines re-invasion into the near well bore. Also fines acidizing alone is merely treating the symptom rather than the underlying cause and it can be assumed that the duration of the benefit is limited to how long it takes for fines to be released and begin to restrict flow again. Thus, a concern for operators is the fact that the benefit of HF acid treatments for fines can be short-lived. Other treatments were developed to fix fines in place21–22 however these systems have not been widely used.

The optimum treatment for fines would integrate techniques to dissolve fines, enlarge pore-throat size to diminish near wellbore particle bridging, and finally to "lock-in-place" those fines that are not removed by the treatment. Furthermore, a long-term, integrated solution must address the mechanism of fines migration so that a comprehensive approach to the problem may be employed.

This paper reviews fines damage mechanisms and presents a fluid system to correct fines damage and prevent fines migration in a single treatment, while keeping acidizing risk at a minimum. The new system uses an organo-phosphonic acid (HV) to generate and moderate HF for deep penetration and an organosilane fines-fixing agent (FFA).
Sensitivity Analysis on the Two-Phase Flow Properties in a Turbidite Reservoir
Authors: Di Pierro Esteban , Stephen Karl D. , McDougall Steven R. M. , Pickup Gillian E.
Published: December 2007

We need to know saturation dependent relative permeability and capillary pressure functions for the reservoir rocks in order to be able to carry out flow simulation successfully. Both of these properties depend on the wettability, which is acknowledged as playing an important role in fluid flow.

We have carried out a sensitivity study of the two-phase flow properties on the production from a turbidite field, starting with network modelling to simulate two-phase flow at the pore scale. A new method has been used to "anchor" network model parameters to existing (drainage) capillary pressure curves. The wettability was varied systematically, and a range of corresponding relative permeability and capillary pressure curves were generated. These curves were then used in flow simulations of a sector of the turbidite reservoir.

Results show that it is very important to consider uncertainties in the two-phase flow parameters because they have a significant effect on recovery.
Horizontal Well Geosteering: The Experience in a Giant Campos Basin Deep-Water Field
Authors: Coutinho M. R. , Abreu C. E. , Braga M. S. , Maciel W. B.
Published: December 2007

Horizontal well geosteering involves careful monitoring of the well during the drilling phase. To this end, relevant geophysical and geological tools are used to build a consistent geological model. Real-time information enables constant updating of this model providing the necessary information for geosteering decisions. These geosteering procedures allow for close control of the well trajectory in the target layer, reducing the risks of redrilling.
Evolution of Drilling Technology in Mature Reservoirs of Lake Maracaibo: Short-Radius Reentries, Horizontal Wells, and Highly Deviated Wells
Authors: Villasmil R. , Segovia G. J. , Valera R. E. , Lopez Ch. , Fernandez A. , Hinestroza D.
Published: December 2007

After 70 years of continuous exploitation in the Bolivar Coast region of Lake Maracaibo, Venezuela (Fig. 1), advanced reservoir depletion is causing drilling problems such as severe loss of circulation, hole instability, and extensive formation damage. In an attempt to optimize drilling performance, several operation practices were implemented through 1997, such as air-, mud-, foam-, and oil-base mud systems, etc., without achieving the expected success. Fig. 1Geographic location.

Because of the challenges of working in these mature fields, the operator and the oilfield services company created a services alliance contract called PRISA (a Spanish acronym for Integrated Drilling and Workover Alliance Services). This paper describes the drilling technologies and best practices used to improve drilling performance in these mature reservoirs, the learning curve evolution, and process improvement. The results included a cost reduction of 12% (in investment cost/barrel), a production increase of 4%, a 58.7% reduction in drilling time, and a drilling cost reduction of 3.6% (Figs. 2 through 3B). In addition, nonproductive time (NPT) has been reduced from 24.1% in 1999 to 3.8% in 2002 (Fig. 4). Fig. 2Drilling time evolution in mature fields in Lake Maracaibo.Fig. 3ADrilling costs evolution in mature fields in Lake Maracaibo.Fig. 3BProduction evolution in mature fields in Lake Maracaibo.Fig. 4NPT evolution in drilling operations in mature fields in Lake Maracaibo.
Stimulation Efforts in Carbonate Gas Reservoir Experiencing Subsidence in Offshore North West Java Field - Indonesia
Authors: Susilo Yoliandri , Rahamanda Zahazny , Wibowo Wahju , Tjahyadi Riza , Silitonga Frans J. , Nasser Iqbal
Published: December 2007

Subsidence and reservoir compaction continues to be significant concern for the oil and gas industry. The decrease of pore pressure during hydrocarbon production (depletion) leads to compaction of the reservoir. When compaction occurs, it changes the porosity and permeability properties of the reservoir rock and can affect recovery efficiency and well productivity. The results of stimulation efforts to improve gas deliverability in carbonate reservoir experiencing subsidence in Offshore North West Java (ONWJ) field are presented here.

The wells in this study were completed in the Parigi Formation, which is a thick carbonate buildup formation with large columns of gas about 250-300 feet thick underlain by aquifer. It has high porosities (32-45%) and good gas permeabilities up to several Darcies with the initial well production were around 20-30 MMSCFD. The continuous production of gas from this shallow, thick and low strength carbonate reservoir has resulted in reservoir compaction, surface subsidence, several well mechanical failures and a sharp production decline (from 15 MMCFD to 2 MMCF). The other impact of declining gas rate that is nearing its critical velocity is causing water condensation that cannot be lifted out of the well; it then accumulates in the wellbore and creates more back pressure on the reservoir.

Treatment efforts, starting from nitrogen kick-off with CT to unload the condense water in the wellbore followed by re-perforation and acidizing job, that were conducted in the first two well have resulted a significant production response. Gas production increases by 4-9 times after the treatment. The previous fear/perception that acidizing would perhaps even worsen the conditions of the reservoir and thus reduce production proved not to be true. These successful treatments have led to stimulation campaigns for other wells in the area.

This paper will also discuss several surveillance projects to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction and wellbore damage in this area.
A Novel Methodology for the Analysis of Well Test Responses in Gas Condensate Reservoirs
Authors: Barrios K. , Stewart G. , Davies D.
Published: December 2007

Single-phase analysis based on pseudopressure has been extensively used in the oil industry to analyse well test data from gas condensate reservoirs. However, the presence of the two-fluid system which forms when the pressure drops below the dew-point requires advanced techniques to derive accurate skin values. This quantity contains contributions from the mechanical, non-Darcy and liquid drop-out components. Many remedial well treatments (acidification, hydraulic fractures, etc) have been designed on such incorrect analysis, the resulting lack of treatment success leading to an unnecessary increase in operational cost. The aim of this study is to develop a full understanding of multiphase flow effects, to establish a systematic methodology using the two-phase pseudopressure function and to obtain accurate results from gas condensate well test analysis.

This work uses the steady-state, two-phase pseudopressure in the same manner as the familiar single-phase pseudopressure analogue.

A 1D compositional simulation model was used to generate the input data for the well test interpretation, special attention being paid to the time step and grid size distribution to avoid numerical truncation errors.

The mechanical skin used varies from negative values (wells with fractures) to positive values (wells with formation damage). A correlation between the skin value obtained from the two-phase pseudopressure analysis and the mechanical skin was derived. This allows the reservoir engineers to make the key discriminations between mechanical skin and liquid drop-out skin.

The approach used here was also extended to generate a general understanding of the production behaviour of condensate production wells e.g. fluid, velocity and relative permeability effects on the resulting pressure drops created by condensate accumulation near to the wellbore. This will find application to well design e.g. the conditions under which horizontal wells can eliminate a condensate bank near to the wellbore can be confidently predicted.
Distribution of Injected Water by Using CGM Method: A Case History in Palogrande-Cebu Field
Authors: Saavedra N. F. , Peralta R. C. , Cobb W.
Published: December 2007

Craig, Geffen and Morse (CGM) Method, one of the most thorough and practical prediction method for waterflooding prediction, was applied to the Palogrande-Cebu Field in Colombia South America to define the vertical distribution of the injected water of a project that has 18 years old. The field has five producing units that had been waterflooded since 1984. The CGM method was adapted to match the actual fluid production rendered confident vertical water distributions and actual water saturation for the different units and for all the producing wells. Methodology was as follows: Analysis of the injection and production curves. For every production well a rigorous analysis of the production curves was compared with the injection curves of the closest injectors. This analysis allowed a selection of the injectors that affected the fluid production of the well in analysis. This step gave a qualitative approach.Injectivity analysis. Logs of water injection distribution were analyzed for all the injectors. This step gave a vertical injection distribution for the five units at the injector but did not give a clue about the areal distribution of the water.CGM method. The CGM was adapted to be able to match the actual fluid production of the field. For each producer, the selected injectors in step 1 were evaluated. Some times it was necessary to include or reject injector wells to get the match of the produced fluids.

The combination of the three steps allowed getting a real view of the areal and vertical water distribution. The above method is been used to get a realistic numerical simulation of the field, since a thorough knowledge of the field has been reached. This paper describes in detail the methodology and the field results for Palogrande-Cebu field.
Deriving Capillary Pressure and Water Saturation from NMR Transversal Relaxation Times
Authors: Glorioso Juan Carlos , Aguirre Omar , Piotti Gabriel , Mengual Jean-François
Published: December 2007

Determination of water saturation (Sw) from conventional resistivity and porosity logs has proved difficult in several gas fields within Bolivia. To address this challenge, a method was developed to determine Sw profiles based on pseudo-capillary pressure curves (Pc) derived from transversal relaxation times (T2 distribution) measured by nuclear magnetic resonance (NMR) logging tools.

Some of the Bolivian sand reservoirs, producing gas and condensate with a high gas/oil ratio, are characterized by a lack of resistivity contrast above and below the oil-water contact. This problem is attributed to complex mineralogy, including thin shale laminations within sand bodies of variable petrophysical quality, and mostly to very fresh formation waters that average a salinity of 5000 ppm of total dissolved solids. Also, the lack of lateral extension of each reservoir makes cross-well correlation very difficult.

The core hypothesis of this original method is to assume that the relation between capillary pressure and pore throat sizes is similar to that between T2 values and pore-size distribution. A consistent scaling factor is used to derive a pseudo-capillary pressure from an NMR T2 distribution. After the pseudo-pressure is calibrated with capillary pressure measurements from laboratory-derived core data, it is combined with density (difference between the produced hydrocarbon and the formation water) and free-water level (FWL) information to compute Sw along the wellbore trajectory.

Even so, in general terms, resistivity-based models are still the most consistent and documented foundation in order to compute water saturation; Examples demonstrate the success of this new standalone method of uncovering unforeseen hydrocarbon in place and obtaining accurate Sw as an alternative to the standard, but dubious or inadequate, resistivity method in Bolivia where cretaceous and carboniferous rocks with intergranular porosity are found within several sedimentary basins.
A Method To Estimate Permeability on Uncored Wells Based on Well Logs and Core Data
Authors: Lacentre Pablo E. , Carrica Pablo M.
Published: December 2007

Reservoir description for simulation studies requires good knowledge of the permeabilities. Unfortunately, reliable permeability is only available from laboratory tests on cores, which are usually taken from a small percentage of the wells. Frequently, this information is extrapolated to calculate permeabilities all over the field, but the lack of enough data points usually causes unreliable predictions. We propose a method to estimate formation permeabilities from standard well logs and core data. The analysis includes a first step consisting of the interpretation of the petrophysics and a characterization in lithofacies, electrofacies and hydraulic flow units. This step involves the use of modern mathematical tools to rationally classify each reservoir region into a given (discrete) hydraulic flow unit. As a second step the core permeability data is mapped with the well log data using neural networks and the restrictions found on the first step of the analysis. This approach allows the use of continuous hydraulic flow unit values and reduces the error arising from the discrete zonation technique. Also, it overcomes the error coming from the mapping between log data and hydraulic flow units. The method should be applicable to any kind of reservoir as long as sufficient core and log data are available. The method assumes that the Carman-Kozeny equation holds for the reservoir rocks, which is a fairly reasonable assumption, and that the well logs available contain intrinsic information on tortuosity, sand size distribution, cementing characteristics, etc., which ultimately determine the flow performance of the rock. This hypothesis is usually strong because the available logs are not able to fully read the physical phenomena that cover the complex dynamics of the flow on the reservoir rocks. The method was tested using available core and log data in a sandstone formation in Chihuido de la Salina, Neuquen Basin, Argentina. Some core data points were not used to train the neural network and therefore useful for validation and comparison. In spite of the cited drawbacks, the method has shown to outperform both the standard regression techniques and the hydraulic flow units approach.
Monitoring Techniques for HP/HT Reservoirs: Furrial Field Case
Authors: Matamoros Valeria , Escobar Elena , Rodríguez Anaiza
Published: December 2007

The continuous monitoring of the main reservoir parameters is usually very important in capturing data, which are then used for reservoir characterization and recovery process evaluation in reservoir studies. This characterization is used to define the production strategy and oil recovery efficiency of the fields. In the case of High Pressure and High Temperature reservoirs, the reservoir monitoring becomes a challenge. The Furrial field, located in Northeastern Venezuela, is an example of a very deep, HP and HT reservoir. During the design and application of a WAG pilot project in this field, several monitoring techniques were considered. Of these, some monitoring techniques were selected and subsequently some of them were implemented in the pilot.

This paper presents some field results related to several monitoring techniques that have been applied during the different phases of the WAG pilot test in the Furrial field. The study considers conventional techniques such as chemical and radioactive tracers, and saturation, temperature, pressure and production logs. Also this study examines unconventional techniques such as natural tracers, pressure and temperature downhole gauges. Finally, the study investigates, new approaches for monitoring such as saturation downhole permanent gauges, post-mortem cores and crosswell seismic. All the techniques were analyzed and compared, considering the reservoir characteristics, application feasibility, market availability, time of response and costs, to select the most suitable techniques for this type of reservoir. The results from the Furrial field case show that even though permanently mounted downhole gauges seem to be the most appropriate way to capture reservoir data for a mechanistic pilot, they are not totally reliable, so far, for HP and HT reservoirs.
The Cruse ‘E’ Expansion Steamflood: Technical, Economic and Environmental Perspectives
Authors: Ramlal V.
Published: December 2007

Based on the success of the Cruse ‘E’ Pilot steamflood, Petrotrin decided to venture into a large-scale project of a similar nature called the Cruse ‘E’ (IADB) Expansion Steamflood. The project area consisted of 270 acres, with an estimated original oil in place of 31.1 million barrels in the zone of interest, the Upper Cruse ‘E’ sand. Surface and infrastructure work began in January 1994, which was followed by rig work - drilling, recompletions, and workovers. Sixty (60) new wells comprising twnty-eight (28) injectors and thirty-two (32) offtakes were drilled and completed to form twenty-eight (28) patterns. Also thirty-five (35) existing wells were utilized as offtakes. The project was commissioned in January 1996 when steam injection began. This brought the number of active steamfloods and WASP projects at Petrotrin to eight (8). It was predicted by reservoir simulation that 11 million barrels of heavy oil would be recovered over fifteen (15) years with production peaking in the year 2000.

However, in 1998 when oil production reached 877 bopd, the project was adversely affected by environmental concerns to a residential area in the vicinity of the steamflood and it was actually shutdown by order of the regulatory body in November 1998. Extensive environmental work was undertaken in the areas of communication, training and operations to improve the safety and environmental aspects of the steamflood, and ensure that it was brought up to the environmental standards required. After forty (40) months of inactivity, approval was finally obtained in March 2002 from the regulatory body to restart steam injection.

This paper discusses the performance of the steamflood during steam injection and during no injection, the technical, operational and economic aspects of the project, and the environmental upgrade conducted.. The paper also discusses the restarting exercise conducted for steam injection and presents future operating strategies.