bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Concentric Coiled-Tubing and Well-Vacuuming Tool With Chemical Sand-Consolidation Resins for Controlling Sand Production in Wells With Damaged Screens or Slotted Liners: A Rigless Well-Repair Alternative
Authors: Medina N. , Diaz J. , Pachon L.
Published: December 2010

Reservoirs comprised of poorly consolidated sands are generally prone to some level of sand production throughout the life of the well. This sand production creates many challenging problems for the operator such as erosion and/or failure of both down-hole and surface equipment, lower well production due to tubular fill-up and, finally, environmental issues related to the final disposition of the produced solids. All of these problems also have a common denominator: they significantly increase the cost of production for the well's in question.

Conventionally, the application of any technique for controlling sand production is recommended as soon as it is known that the problem exists. Among some of the solutions available are 1) sand control by mechanical means using slotted liners and screens combined with conventional gravel packs, 2) prepacked completion screens, 3) lowering the production of the well thereby reducing the draw-down across the formation and 4) chemical sand consolidation (CSC) resin treatments: the latter being the focus of this paper.

The principle behind the CSC process is the adherence of sand grains to a liquid resin that, while cross-linking occurs, penetrates and hardens across the porous matrix. The newly create mass of consolidated sand exhibits much higher mechanical strength, able to withstand the drag forces generated by oil production.

CSC resins can be injected either when a well is initially completed or during workover operations which are needed to clean a sanded-up well-bore where said sand deposition is the result of failed completion screens or slotted tubulars. In such cases, the CSC resin acts as a plug across the heightened sand producing area and represents an economically viable alternative to complete replacement of the damaged tubulars or, as a worse-case scenario, well replacement.

This paper will discuss a combination of technologies where both CCTWV (used to clean the well and detect the sand intrusion points) along with CSC resin technologies were used to successfully repair two wells in the unconsolidated URD-01 reservoir that were producing sand through holes in 5″ Slotted Liner and 3-½″. pre-packed completion screens.
Methods and Benefits of Knowledge Sharing in the Petroleum Industry
Authors: Shadravan A. , Amani M. , Molinari D. , Hugall J. N.
Published: December 2010

In the year 2030, global energy demand will be almost 35% higher than it was in 2010, led by a power hungry world population of almost 8 billion. This looming energy crisis must be tackled by forming stronger inter- and intra-company collaborations,to maximize their exploration and production. Knowledge sharing (KS) is essential in every sector of all societies; employed as the main tool for achieving progress. It is the necessary key to make these stronger partnerships, providing networking communities in which to share information for the good of the organization.

There are many ways in which an organization can use knowledge sharing as an effective tool for gaining success, such as: websites and forums; peer-reviewed journals; conferences; and educational programs. Benefits of knowledge sharing include: enhanced learning opportunities and intellectual stimulation for employees; increased company efficiency; advances in R&D and in particular with forums, the creation of a searchable archive of previously answered questions for future use.

Should all organizations decide to adopt these cost-effective techniques, they would not only increase their capital but also help to solve the global energy crisis with more effective R&D in exploration and production. Organizations that enable their employees to access and interact with their company's knowledgebase are more likely to succeed than those whose individuals have limited sharing opportunities. This paper investigates some knowledge sharing methods that could bring success to a company and scientific societies in the competitive petroleum industry environment.
Reducing Exploration and Appraisal Risk in Low Permeability Reservoirs Using Microseismic Fracture Mapping—Part 2
Authors: Cipolla C. , Mack M. , Maxwell S.
Published: December 2010

The exploration and appraisal of low-permeability or unconventional hydrocarbon resources is significantly different than conventional reservoirs; exploration is more like appraisal, requiring pilot programs to test commerciality of these plays prior to embarking upon large-scale development (Hall 2007; Stabell et al. 2007), including the effect of completion and stimulation optimization (Haskett and Brown 2005). One essential component of low-permeability reservoir development is hydraulic fracturing, which virtually all of these wells require. With the introduction of hydraulic fracture monitoring (HFM), we are now able to measure fracture geometry and complexity, which has led to major improvements in treatment designs, well completions, and field development strategies in North America. HFM applications were once focused on development and infill drilling, but they have recently shown significant value for exploration plays (primarily in gas shale). HFM measurements now allow operators to more efficiently evaluate the effectiveness of stimulation treatments and completion approaches in exploration and appraisal wells, reducing the number of wells required to assess the economic viability of low-permeability reservoirs.

The application of HFM to exploration and appraisal programs outside North America could significantly accelerate the evaluation of low-permeability reservoirs, where selecting the appropriate hydraulic fracturing design and well completion strategy will be key to success. It could also accelerate the learning curve, which is essential to quickly reducing costs and improving well productivity and hydrocarbon recovery. This paper presents several case histories that illustrate the application of microseismic mapping to characterize hydraulic fracture growth and improve stimulation designs and completion strategies, and demonstrates that the limitations on well locations required to implement microseismic mapping do not significantly increase the cost of the appraisal program.
Subsidence Prediction and Casing Integrity With Respect to Pore-Pressure Depletion With 3-D Finite-Element Method
Authors: Shen Xinpu
Published: December 2010

Pore-pressure depletion arising from oil production can cause subsidence of overburden formations as well as casing failures. The reduction of casing failure in a field containing compactable reservoirs is particularly significant to the reduction of non-productive time. Casing integrity can be influenced by various factors, including formation loading and inner pressure applied to the casing. This paper focuses primarily on a numerical analysis of casing failure caused by the formation geostress load related to pore- pressure depletions. Three-dimensional (3-D) numerical analyses of formation subsidence and related casing failure of a deviated well in a field of offshore Brazil was performed. The calculations considered pore-pressure depletions in the area around a production well and of nearby wells. A fully-coupled hydro-mechanical model was adopted to simulate the porous flow that occurred simultaneously with matrix deformation. Submodeling technique was adopted to address the discrepancy between the scale of the oilfield and that of the casing section. A full-field scale was used to simulate seabed subsidence at a global level. Casing failure was calculated at a local level at the scale of 10 m. The subsidence contour at the field level was plotted as cross- sections of the areas under study for the total formation depth of 10 km. The key casing section along the entire trajectory length was selected by using the finite-element method (FEM). For a given three-year period of production, two submodels were selected, which correspond to the various key-casing sections selected. Plastic deformations of each key casing section with different maximum formation loadings for the two different pore-pressure depletions have been given out. The numerical results of seabed subsidence simulations closely correlate with the measured data from references. The casing failure analysis also matched the observed phenomena. The proposed numerical procedure provides an effective tool for casing integrity estimates and prediction of production-related subsidence.
Laboratory Investigation on Light Oil Air Injection
Authors: Dubey N. K.
Published: December 2010

The Thermal EOR processes are the best available technique for ultimate oil recovery for many oil fields. Generally, there are two categories of thermal methods employed in the field: In which heat is produced at surface (Hot fluid injection) &In which heat is created in the formation (ISC-In situ combustion).

By comparison, heat loss is not generally a limiting factor for In-Situ combustion method.

In this paper, we will discuss the Laboratory procedure involved for the recovery of oil & gas by using compressed air techniques on light oil through the Combustion tube chamber associated with stimulated reservoir temperature and pressure condition.

The difference in case of fuel requirement in air ISC and O2 ISC is 0.2 millions of btu and in terms of cost $ 0.4 per million btu. So efficiency for the O2 will be highest compare to other. Further combustion is divided into forward and reverses according to mode of operation. Combustion front approaches at a point in a porous media containing oil and gas and move from injector to production well via creating various zones. The chemical reactions associated with the LOAI (light oil air injection) process are numerous and occur over different temperature ranges. Results carried in the laboratory gives the idea of oxygen utilization was 91.08% and average peak temperature was 505.879°C. So Air injection in light oil is a new technique to improve the recovery from heterogeneous and water flooded reservoirs.
An Evaluation of the Impact of Reactive Perforating Charges on Acid Wormholing in Carbonates
Authors: Diaz N. J. , Bell M. R. , Hardesty J. T. , Hill A. D. , Nasr-El-Din H. A.
Published: December 2010

The introduction of reactive perforating systems has led to tremendous improvements in well stimulation and productivity. Reactive charges generate a secondary energy release in the perforation tunnel immediately after it is formed, breaking up and expelling debris to leave clean tunnels across the perforated interval, irrespective of formation properties.

Although Bartko et al. (2007) have shown that clean perforation tunnels facilitate the evolution of a single, deeper-penetrating wormhole, there are no reported applications of reactive shaped charges in carbonates prior to acid stimulation. The present study was instigated to evaluate the impact of reactive charges on acid wormholing in representative carbonate cores.

A set of oil-saturated cores have been perforated under simulated downhole conditions, using either a conventional or a reactive shaped charge of equal explosive load. After CT scanning to eliminate outlying perforations affected by rock property anomalies, the set of cores were subjected to identical acid injection treatments representative of typical carbonate reservoir stimulations. Time to breakthrough and effluent chemistry were both analyzed and recorded. Finally, post-stimulation CT scans were used to evaluate wormhole morphology.

The laboratory experiments showed that reactive charges provide cleaner perforation tunnels with higher injectivity, which is beneficial for any type of stimulation job. Higher injectivity tunnels help to propagate more dominant and straighter wormholes resulting in less acid to propagate a given distance. This technology has a significant potential when perforating tight formations or heterogeneous intervals, where obtaining clean tunnels with conventional perforators is most challenging. Further research work needs to be done to evaluate if the difference in acid volume to breakthrough observed in the experiments would have a major impact in the field.
Preliminary Assessment of Tambaredjo Heavy Oilfield Polymer Flooding Pilot Test
Authors: Manichand R. , Mogollón J. L. , Bergwijn S. , Graanoogst F. , Ramdajal R.
Published: December 2010

The literature screening criteria for polymer flooding established the maximum oil viscosity at 150 cP; however, oil price increases and technology improvements have encouraged pilot tests in heavy oilfields. This paper shows the results of an ongoing polymer flooding pilot test in an inverted 5-spot well pattern in an onshore field in Suriname. The reservoir is fluvial deltaic with 900 ft depth in the pilot area. The oil viscosity is 400 cP at 97°F.

The objective of the pilot test is to demonstrate that the production rate and recovery factor can be increased economically to extend the productive life and profits of the oilfield. Polymer flooding began after laboratory, numerical simulation, and preliminary economical evaluations indicated its feasibility. The analysis of reservoir-related parameters showed that uncertainties in long-term injectivity, polymer stability, wells communication, and fluid fingering-channeling cause a high-risk index. Therefore, a detailed subsurface surveillance and monitoring program was prepared and implemented. This program was guided by way forward road maps that target injection, flooding performance, and production assessment, and are based on a "plan, do, check, and act" approach.

To date, 0.22 pore volume (PV) of the well pattern has been injected. The bottomhole pressure (BHP) of the four producer wells has increased by 1.7 to 2.7 times, showing the communication with the injector well, hence, after production has been adjusted to maintain the BHP between 75 to 100 psi. The injectivity is greater than the value estimated for profitability. Polymer breakthrough occurred in two of the 5-spot wells after approximately one year of injection, as forecasted in the reservoir simulation. A slight increase in the pattern oil production and water-cut reduction has been observed. Therefore, incremental oil production is expected in the forthcoming months.
Rigorous Drilling Nonproductive-Time Determination and Elimination of Invisible Lost Time: Theory and Case Histories
Authors: Maidla Eric , Maidla William
Published: December 2010

This paper addresses the measuring techniques that involved data quality control and automatic drilling operations detections of routine drilling operations that are available today in modern drilling programs, and goes through examples of how implementation was carried out in the onshore area that drilled a series of similar wells. Measurement accuracy, training, and the development of new work processes were successfully implemented that led to major KPI (Key Performance Indicator) time savings between 31% and 43%.

You cannot improve what you don't measure. And in this case you cannot measure without a proper data quality control (QC) procedure in place.
Breaking Old Paradigms With the Use of High Performance Water Base Mud Systems
Authors: Rodríguez Sandra , Arenas Ricardo , Sierra Humberto , Montoya Carlos , Serrano Mario
Published: December 2010

Hundreds of wells have been drilled since the early 1900's at the Putumayo basin in southwest Colombia. ECOPETROL (NOC) used traditional mud systems: lignosulphonates, potassium chloride, and finally lime or gypsum mud systems, all of them designed to manage exposure to anhydrite, a common mineral in the drilled formations. The calcium contamination adversely affects mud system properties, resulting in hole instability and frequent stuck pipe events.

Because of these issues, the operator considered using oil base mud (OBM) in a very environmental sensitive area. The OBM would generate undesirable waste and there were uncertainties about its performance, since few wells in the area had been drilled with OBM and the results were not very successful. Therefore, for drilling operations on the ECOPETROL Sucumbíos No. 5 well, a completely new high performance water base mud (HPWBM) was proposed and accepted. The new chemistry eliminated the use of bentonite and included a new flocculation inhibition mechanism, as well as new and powerful polymers. The system demonstrated that calcium and anhydrite were not a problem any more and the well was drilled in record time. More importantly, to the operator was able to evaluate the productive formations by running electrical logs, an operation that was normally cancelled because of severe hole problems. Casings strings were set and cemented per the well program and the well was completed as planned.

This paper presents the design state of the HPWBM, its performance while drilling and charts and graphics comparing the changes against the historical values recorded in the area.
Field Application of a Rig Less Practical Method for Stimulation of Beam Pumping Wells
Authors: Jaimes M. G.
Published: December 2010

One of the main mechanisms of damage at the sand face in the Lisama oilfield (Santander-Colombia) is the organic precipitation, which causes blockages on the perforations and reduces the production of oil, significantly increasing the cost per produced barrel. To remove this damage and recover production levels, chemical treatments are applied in cycles of 14 months, which are selectively squeezed in the formation to a radius of approximately three feet, using workover rig, a set of packers and pumping equipment. The Mugrosa formation is quite depleted and in many cases, organic stimulation by conventional methods is uneconomical (170000-200000 U.S. $ / well).

A method of stimulation to be used in beam pumping wells without Workover equipment (the Rig represents over 70% of the cost of treatment), using the energy of gas (high GOR wells producing from Mugrosa formation), which could reduce costs and make economically viable stimulation treatments in depleted wells, was designed. Successful of a solvent treatment depends on the proper solvent selection and how it is going to be placed in the well.

This paper presents the development of the designed method and its application in the field in the well Lisama 91 located in the Middle Magdalena Basin in Colombia, where the oil production was increased from 30 to 60 BOPD and stimulation treatment costs were reduced by 75 %, in comparison with conventional methods.
Challenges and Solutions to Optimize the Operation of Heavy Oil Fields in Remote Environmentally Sensitive Wetland Areas
Authors: Dodson R. J. , Anthony E. , Schuitemaker A.
Published: December 2010

Heavy oil (16 – 18 APIo) production operations in Staatsolie's Calcutta field in Suriname can be classified as very complex since it is associated with very heterogeneous and discontinuous shallow (± 1000') reservoirs in remote environmentally sensitive wetland areas that are difficult to access as they sustain unique protected ecosystems.

To optimize productivity and mitigate the risks of operating in this complex environment, fit for purpose technologies and tailor made processes were implemented to address the challenges to:

Choose a production method that sustains a very sensitive ecosystem, ensuring efficient mobility of personnel and equipment with minimum impact on the environment, deal with the high cost of intra-field transportation, deal with the high costs of transportation of produced fluids to the nearest treating facility due to zero disposal in the swamp and dispose drilling fluids

To address these challenges the following solutions were implemented:

A wetland operations strategy was implemented whereby there was no land reclamation to setup production and surface facilities thus minimizing the impact on the ecosystem, a totally self-contained hovercraft-type drilling platform is used to drill wells in the swamp, for well servicing a fit for purpose servicing rig is used, uniquely modified Multi Phase Flow Meters for relatively low producing and low GOR wells are used and surface and subsurface facilities are remote monitored

This very unique mixture of solutions with technologies and fit for purpose processes present new perspectives in resolving particular challenges regarding the economical development of a heavy oilfield in an environmentally sensitive area.
Techniques to Improve Flow Profiling Using Distributed Temperature Sensing
Authors: Wang X. , Bussear T. , Hasan A. R.
Published: December 2010

The emergence of Distributed Temperature Sensing (DTS) has led to much better instrumented wells, enabling operators access to real-time temperature data. Sophisticated nodal thermal/fluid models that analyze such temperature data provide many benefits and offer valuable information. Flow profiling is one of the most important field applications of DTS.

Since temperature changes caused by fluid flow are typically small, the temperature resolution or noise level of the DTS traces becomes the limiting factor for accuracy in flow profiling. Noise can be caused by many factors, such as the time length to generate the trace and losses from optical connectors or splices. The two techniques most commonly used to reduce temperature trace noise are (1) averaging of separately measured traces; and (2) formation of a moving average along the trace (smoothing). The latter technique – smoothing – comes at the expense of a reduction in spatial resolution. Another limitation for DTS used alone for flow profiling is that it can only handle single-phase flow situations. Additional information, such as multi-point pressure data, is often needed for multiphase fluid flow profiling.

In this paper, we describe our work with Fourier series to approximate DTS traces which offers greater flow profiling accuracy and avoids spatial resolution reduction. Our mechanistic model couples energy and momentum transport, enabling us to handle multiphase flow by integrating multipoint pressure measurements with DTS.

This paper contains three field examples that demonstrate the following techniques resulting in improved flow profiling: Use of Fourier series to approximate DTS traces (Fourier Approximation);Use of Solver to determine Fourier series coefficients to minimize the sum of the squared error between the DTS traces and Approximation;Use of iterative procedures to determine the best fit overall time interval T; andIntegration of multipoint pressure data with DTS for multiphase fluid flow applications
A New Inflow Model for Extra-Heavy Crude Oils: Case Study Chichimene Field, Colombia
Authors: Arenas F. Guarin , Garcia C. A. , Prada C. A. , Leon E. Cotes , Santos N.
Published: December 2010

Chichimene field is a heavy oil field located in the little deformed sector known as the "foreland ‘basin plains of Colombia. This field is located in Castilla La Nueva in the Meta Department in the east part of the country. Chichimene field was discovered by Chevron in 1969 with the drilling of Chichimene-1 well (CH-1), but it only started production in 1.985. Since 2.00 Ecopetrol S.A has been in charge for field operation.

Chichimene field produces a medium crude oil (approximately 20 API) from cretaceous structures named K1 and K2, In 2.01 an extra heavy crude oil (range between 7 – 9 API) from a terciary (T2) formation named San Fernando started production with the CH-18 Well. Despite of the high density presented, the T2 crude oil is mobile at reservoir conditions due to an abnormally elevated reservoir temperature

The interest formation corresponds to an elongated northwest direction tertiary anticline layer, the crude oil discovered in this structure is extra-heavy produced by severe biodegradation and evaporative fractionation processes, the depositional model is associated to a distal marine Cretaceous rock. Nowadays the San Fernando formation produces about 14,000 BOPD using electric submersible pumps (ESP) as artificial lift method.

This paper reviewed the conditions of the reservoir (petrophysical model, PVT properties, Oil, water and gas production behavior), the physical property of the produced fluids and fluid characteristics of foamy oil properties, to establish an appropriate mathematical expression for modeling the performance of these extra-heavy oil wells.
A Reliability-Based Systemic Method for Water Production Analysis, Diagnosis and Solution Design
Authors: Reyes C. M. , Azuaje E. , Ortiz-Volcan J. L.
Published: December 2010

This practical method integrates petroleum engineering knowledge, reliability and six sigma tools in a reservoir production system model representing all potential cause effect relations and failure modes to identify the origin of water production and its classification as wanted or non-wanted. A general process is proposed to design a custom made solution for either controlling or handling water production. The solution is modeled with systems dynamics and stochastic simulation to calibrate cost, benefits, cycle time and required resources and data acquisition to close the loop during the life cycle of the field.

The method has seven macro processes: 1) Data gathering and reliability analysis, 2) Determination of non wanted water production, 3) Analysis of causes related to mechanical problems in the well, 4) Analysis of causes related to well drainage area, 5) Analysis of causes related to the reservoir, 6) Definition of corrective and preventive actions and 7) Cost, cycle time and resources modeling to design a solution with the required actions during the life cycle of the field.

Two examples from two fields in Venezuela are used to describe the application of the method. In these examples cycle time including solution design and implementation is 80 days with a total cost ranging between 300 to 600 thousand dollars.

We provide a road map for water production analysis, diagnosis and solution design in oil and gas reservoirs that can be adapted custom- made to any field to address water origin identification, classification as wanted or non wanted water and solution design. This method is non-commercial so it can be used by operators as an alternative to others that could be biased to particular technologies. If used appropriately this method could increase hydrocarbon recovery and reduce risks and costs of environmental impact of water. Finally, this method is a framework for standardization of existing work processes and for integrating the work of all disciplines required for managing water production in an integral way.
Influence of Stress Field in the Productivity of Naturally Fractured Reservoirs in Metamorphic Basement: A Case Study of the San Pedro Field, Amotape Group
Authors: Meza O. E. , Peralta V. , Nuñez E.
Published: December 2010

San Pedro is a complex reservoir located offshore Bayovar Bay in the province of Piura in northern Peru. Stratigraphically, is located in metamorphic basement rocks of the basin Sechura, composed of Paleozoic rocks Amotape Group. The San Pedro reservoir corresponds to a naturally fractured reservoir, its structural complexity is linked to tectonic events that led to the formation of different types of fractures and presence of structural forms own metamorfics rock.

Geophysical characterization of the major structural features as faults and fractures, and characterization through special registers such as image registration, sonic dipolar and sonic scanner, conventional records which are taken as inputs for the construction and validation of continuous models petrophysical properties, discrete fracture models and geomechanical models in order to best characterize this reservoir.

Due to the highly complex network of fractures, well productivity is highly variable along the reservoir and is heavily influenced by the prevailing current effort in the field. The productivity of wells due to a directional permeability generates a drainage area of elliptic type which is difficult to define but which is reflected in the productive performance of wells and gas injection projects that were made in the reservoir. The productivity of the wells is also largely affected by the type of completion used in different parts of the reservoir, the completion type generally used "open hole" which has worked well in some parts of the reservoir but in other not because of the influence of the efforts and the structural forms that it has created.

All these models and production data history help us understand the nature of the dominant effort, the main trends of productive fractures and to identify areas and blocks with potential for further drilling of wells and carry out the development plan the field.
It Is All About Pressure: Drilling a High-Pressure Well in Record Time Using Real-Time Tools
Authors: Santos Gustavo , Serrano Mario , Villa Leonardo , Nieto Eduardo
Published: December 2010

The Lisama field located in the middle Magdalena basin is well known as one of the high pressure areas drilled in Colombia by ECOPETROL (NOC). Densities up to 21.0 ppg are often reached and side tracks due to hole instability are common in the area, sometimes as many as three (3) per well, making plans in days and costs difficult to control.

The use of real time tools such as Pressure While Drilling (PWD) on the Lisama No 167 well demonstrated that only monitoring the fluid density at surface is not enough to keep the hole open and stable. Monitoring with PWD demonstrates that real annulus pressure involves all kind of parameters affecting the mud density including temperature, solids content and compressibility, so that the real pressure and the Equivalent Mud Weight (EMW) can be determined at any point of the wellbore. In this directional well, the challenge for the service company is to use an MWD system that works with high-density fluid conditions. Conventional systems have an operational limit of 18.0 ppg, so an electromagnetic telemetry system was chosen.

Through continuous ECD monitoring and EMW management, combined with a good drilling plan plus the use of electromagnetic telemetry systems, it was possible to keep the wellbore under control and reduce operational time to 60% below the offset wells drilled in that area. The Lisama No. 167 well reaches expected densities around 21.0 ppg, enough to keep pore pressure under control and drill to the final depth of 7390 ft without problems. The successful combination of PWD tool plus electromagnetic telemetry made it possible to identify the events requiring improved hole cleaning, increased mud weight and optimized drilling parameters. It also facilitated decisions regarding circulating, tripping or casing point selection.
Massive Optimization Technique Improves Production of Mature Fields: San Francisco, Colombia
Authors: Suárez Andrés Felipe , Soto David , Borja Hubert , Daudin Remi
Published: December 2010

A breakthrough methodology has been implemented in the San Francisco field, Colombia, to yield an additional 12% in remaining reserves by optimizing production and injection based on key principles of the ‘learning theory’.

This paper presents a new massive optimization methodology applied in the San Francisco field. Such techniques are especially well suited to mature fields, as these have substantial infrastructure in place, which can be used in ways different to the usual.

Mature fields represent a challenge in terms of investment and allocation of resources. Still, there remain opportunities to improve production, since past strategic choices have created some heterogeneity in field pressure and saturation. These can be drastically revisited and production parameters rearranged. Since many production avenues have been explored in the past, a learning process can be applied: rearranged parameters can be implemented with very low risk. Still, there are billions of ways to operate mature fields: injection and production rates can be varied, conversions made.

Massive optimization of a field means selecting and playing with thousands of production scenarios and identifying the best. This is possible only with a reliable and fast simulator. The "statistical learning theory" defines under which conditions such a simulator can be devised. The Production Simulator is designed in such a way that it complies with the conditions of a reliable long-term forecast.

This new approach has been successfully implemented in the San Francisco field in order to re-organize the water-flooding regime, in particular through the conversion of producers into injectors. The entire process took only three months.

Our methodology has led to an expected additional production of 1.2 mmbo, a +12% increase in remaining reserves, with a total development cost of 4.5 US$/bbl. Current production data, one year after implementation, is in line with the forecast.
Casing-Drilling Application in the Depleted La Cira Infantas Mature Field, Colombia
Authors: López E. A. , Bonilla P. Antonio
Published: December 2010

Field redevelopment reflects the unique foci of the integrated project team built between Ecopetrol and Oxy to redevelop the LCI oilfield. La Cira Infantas (LCI) is the oldest Colombian field, production started almost at the beginning of the twentieth century and since late 2005 is under a redevelopment phase, increasing production by more than 5 times in less than 5 years. Redevelopment involves over 1500 wells being drilled or worked over in order to increase recovery factor by about 8% from the C sands. Hundreds of wells are scattered throughout this brownfield which is divided in two principal areas, Cira and Infantas. This field is crossed by faults characterized by depleted and shallow gas bearing formations, challenging drilling with loss of circulation and well control issues, somehow unpredicted given the faulty nature of the area and the impact on the producing sands of previous EOR and drilling campaigns (early to mid twentieth century) (Fig. 1).

This paper will describe the benefits of using the casing while drilling technology to drill wells where loss of circulation is anticipated, successfully eliminating flat times that otherwise would be used to cure losses when drilling conventionally due to the smearing effect which is enhanced by the addition of bridging agents and loss circulation material; and setting casing at the planned TD.

Drilling with casing has shown that 10% cost reduction and 30% time savings were achieved against conventional drilling, with additional potential to reduce costs and time by improving the operational times employed for drill-out, BHA recovery, and cementing operations.
Drilling Optimization of Wells From Crater Field: Decreasing Drilling Times and Operational Risks
Authors: Tellez Carlos Perez , Santiago Hector Mandujano , Puentes Ferney , Isacci Jose , Marino Luis , Obediente Rodolfo
Published: December 2010

In the past, wells drilled in Crater field required an average of 310 days to reach total depth (TD), mainly because of operational problems, including drillstring twist-off, stuck pipe, unplanned sidetracks, excessive directional complexity when drilling, and under-reaming. Low rates of penetration (ROP) while drilling the Eocene and Paleocene intervals also impacted drilling time.

Design optimization provided by a major service company allowed the operator to finish the recent Crater-52 well 95 days ahead of plan and 155 days ahead of the average duration for previous wells. This achievement significantly reduced operating costs and helped facilitate an anticipated production of 285,000 barrels of oil.

Key achievements are summarized below:

Drilled the 17.5-in. section 500 m deeper than the original design using 5.5-in. drillpipe instead of the traditional 5-in. Set 9.875-in. casing at the Medium Eocene Level, which made it possible to drill the 8.5-in. section with a much lower differential pressure, increasing ROP from 1 to 5 m/hr. Saved $3.4 MMUSD in operational costs and recovered 285,000 barrels of oil ahead of schedule. Reduced non-productive time (NPT) from 30% to 5.5%.

Lithological characterization, calibration, and updating of the geo-mechanical model helped the operator drill 500 m deeper in the 17.5-in. section, which eliminated the need for hole enlarging in two problematic sections. Using 5.5-in. drill pipe improved hole cleaning, with faster ROPs as a direct consequence. Drilling the 12.25-in. section to the Medium Eocene made it possible to drill the 8.5-in. section with lighter mud weights, decrease differential pressure, and elevate ROP. Lost circulation risks were also minimized. The NPT was 83% lower than the field average.

Based on these results, future Crater field well designs will also be optimized, and the drilling team is evaluating the feasibility of applying the optimized design in other fields. The improved hydraulics parameters helped increase hole-cleaning effectiveness and ROP while preventing operational incidents in the 17.5-in. and 12.25-in. intervals.
Application of an Artificial Neural Network ANN for the Correction of NMR Total Porosity, Effective Porosity and the Bulk Volume Irreducible Water Data Obtained from a Heavy Oil Reservoir using an Oil Based Mud Drilling Fluid in the Samaria: Tertiary on the Southeastern of Mexico
Authors: Granado L. M. , Sosa J. C. , Galicia J. A. , Rodriguez-Monroy R. , Escamilla G. , Ponce B. , Rueda M. C. , Quirein J.
Published: December 2010

Samaria Tertiary field in southeastern Mexico produces extra-heavy to medium grade oil (5 to 23° API) from sand-shale sequences. It is well known that the nuclear magnetic resonance (NMR) logging application can provide the total and effective porosity values, as well as free and related fluids independent of mineralogy. When the NMR logging tool is run in heavy oil deposits, oils of varying viscosities can be distinguished qualitatively. Unfortunately, however, in the presence of heavy oils, this measurement process underestimates the total porosity and effective porosity, and overestimates the bulk volume irreducible water (a key parameter for estimating permeability). Although the literature specifies methods that can correct this porosity and fluid volume bias by using fundamental magnetic resonance principles and conventional borehole information, they are only effective when the drilling fluid used is water-based mud.

The artificial neural networks (ANN) have traditionally been used to correct well log data corrupted by tension pulls on the tool or degraded by poor borehole conditions. They have also been used for cases in which it is not feasible to obtain a traditional set of openhole well log data. In such cases, a neural network is used to generate synthetic openhole data from pulsed neutron logging data.

In this application of ANN, the data is first manually interpreted to delineate uncorrupted zones of the data. This interpretation will correspond to zones in which there is no hydrocarbon or the hydrocarbon type is not heavy oil. The aggregate of such zones is used to define a training set. The remaining data is used to define the application data set. Traditional openhole data (such as resistivity, neutron, bulk density, and thorium) is used to train a neural network to predict NMR fluid volumes. The network obtained is then applied to the application data set, and it is shown that the resulting predicted NMR fluid volumes have been corrected for heavy oil effects in the presence of oil-based mud.

This paper demonstrates the effectiveness of this approach and discusses the results obtained. It also demonstrates how the process can be automated.
Analysis of Operative Variables for Establishing a Procedure to Obtain Representative Fluid Samples in Gas/Condensate Fields
Authors: Torres T. R.
Published: December 2010

During the exploratory phase, reservoir fluid analysis is an important tool for obtaining the hydrocarbon volume In-Situ, for understanding the behavior of fluids based on the field pressure changes, for defining a fluids production strategy, and as an input for production facilities design, among others. Due to the importance of this information, sampling procedures must guarantee that collected fluids are representative of reservoir ones to allow for reliable results which will be obtained during the PVT laboratory studies.

In the ABC Fieldcase, located in Cusco Peru, a Gas-Condensate reservoir with a dew point close to the initial reservoir pressure, it was necessary to develop a detailed operative design in order to guarantee that fluid samples would be representative. This study allowed us to define some steps which must be present in the operative procedure in order to achieve an optimum sampling process.

Additionally, it was possible to see the effects in the representativeness of the samples due to pressure depletion, condensate banking, and its compositional analysis. The behavior of the Gas-Condensate ratio, the turbulent flow effects in the formation face, permeabilities, the optimum time for sampling, and flow rates.

Finally, it was possible to evaluate the sampling procedure effects and its influence in the representativeness of fluid. An equation of state tuning was carried out for two fluids which were sampled in the same well. In this case, the effects of the different sampling procedures and their repercussions in liquid recovery are analyzed.

With the information contained in this study, we can identify the importance of selecting an exclusive sampling period outside of the normal transient pressure testing period and the effects of the main system variables. Keeping in mind the importance of this information and the costs associated with the project, failure is not an option.
A New Methodology for Prediction of Bottomhole Flowing Pressure in Vertical Multiphase Flow in Iranian Oil Fields Using Artificial Neural Networks (ANNs)
Authors: Mohammadpoor M. , Shahbazi Kh. , Torabi F. , Qazvini A.
Published: December 2010

In this paper, Artificial Neural Networks (ANN) are used to predict the bottom-hole flowing pressure in vertical multiphase flow. Two-phase flow of gas and liquids is commonly encountered in the production and transportation of oil and gas. Knowing the bottom-hole pressure (BHP) of a well and the productivity index (PI or J) can help predict the well potential during its life-cycle. In other words, well production monitoring can be performed, which is a key objective for oil production maximization and operational cost reduction. Different correlations considering different operating conditions and flow models were studied in order to find the most effective input parameters. ANN accuracy is highly dependent on the validity of the input and output data. After gathering the input and output data from selected southern Iranian oil fields, all the data were filtered with the help of existing models to eliminate the unreliable data. Then, 167 data sets were normalized and carefully imported into the ANN models. Different ANN models with different numbers of hidden layers and transfer functions were developed and tested, and the best one with the least error was chosen. The accuracy of the pressure predicted by the developed ANN model was improved by approximately five times as compared with existing correlations. To show the accuracy of the method, the results are compared with those obtained from the existing correlations.

Accurate prediction of pressure drop in vertical multiphase flow is needed for effective design of tubing and optimum production strategies. Different kinds of two-phase flow correlations have been developed and are currently being used in industry. In addition to the limitations on the applicability of all existing correlations, they all fail to predict the desired accuracy of pressure drop predictions.
New High Density Phosphate-Based Completion Fluid: A Case History of Exploration Wells: KRE-1, BOP-1, TBR-1 and KRT-1 In Indonesia
Authors: Sangka N. B. , Budiman H.
Published: December 2010

Due to its capacity and stability in extreme subsurface conditions, such as in HTHP and high concentration of sour gas and because of its non corrosive, re-useable, low cost and environmentally friendly, high-density Phosphate based Completion Fluid (CF) has been used in several exploration wells in Indonesia.

The main challenges during testing in exploration wells with extreme subsurface condition and high concentration of sour gas was how to maintenance and keep CF stability properties to support operating testing devices.

In exploration well KRE-1 in West Java Field, in a fracture Metasediment and Conglomerate lithology, subsurface conditions of HTHP, H2S 21 ppm, and CO2 25%, the Non Productive Time (NPT) that related with testing was 202.5 hours due to the constraints in the testing device, both the string configuration and the rubber component, it were caused by unfamiliarity in handling this brine.

After the evaluation, we changed the CF field handling and changed a configuration and specification of testing device.

The result showed that the CF properties bécame stable and the operational testing worked well.

The same procedures were applied in three exploration wells from different fields with several characteristics lithology and subsurface. First well BOP-1 in Bunyu island Field, in Sand-Shale-Silt-Coal lithology with subsurface condition of swelling shale with loose sand. Second well TBR-1 in East Java Field, Limestone lithology with subsurface condition of high concentration H2S up to 20.000 ppm and CO2 35%. Last well, KRT-1 in fracture Metasediment, Conglomerate, Sandstone and Limestone lithology and subsurface condition of HTHP, H2S 13 ppm, and CO2 6%. The related NPT with testing gradually dropped to 119.5 hours and then 78 hours and finally only 2 hours.

This paper describes the field experiences of handling Phoshates based CF during testing with lessons learned for operational testing devices from testing companies.
Analysis of the Effect of Different Forchheimer's Beta Correlations in the Results of Numerical Simulation of Gas Flow in Naturally Fractured Reservoir
Authors: Souza G. , Zacchi A. L. , Barretto A. B. , Pires A. P.
Published: December 2010

This work focuses the numerical simulation of gas flow in naturally fractured reservoirs (NFRs), when non-Darcy effects play an important role in the pressure behavior. Based on the conservation law of the gas phase, the real gas compressibility model and the Forchheimer's Equation, a code was developed to solve the hydraulic diffusivity equation and used to evaluate the pressure behavior when Darcy's Law does not model flow adequately. A layered reservoir model was considered to represent fractures. The discretization of the system of nonlinear equations was made through the finite difference method, the implicit formulation was applied and the bi-conjugate gradient method was used in order to obtain the numerical solution. The physical problem is related to equilibrium between viscous and inertial forces. At moderate flow velocities in porous media, pressure gradient is proportional to fluid velocity and can be expressed by Darcy's Law, based on viscous effects. However, at high velocities besides viscous forces there is also a force component due to inertia. In these cases, Forchheimer's Equation, which includes non-Darcy effects through a non-linear term added to the Darcy's Law, is an alternative to model compressible fluids porous media flow. The non-linear term has a factor called Beta, a function of permeability, porosity and in some cases of tortuosity. In this work, our main objective is the analysis of the effects of different correlations for Forchheimer's Beta factor in the wellbore pressure behavior. Results for pressure and pressure derivative followed the typical and expected behavior of the reservoir model chosen for fractures. Furthermore, comparison involving simulations with and without addition of non- Darcy effects showed significant differences between results, confirming that production flow rate, permeability and fracture thickness present strong impact on the reservoir depletion. Influence of Beta correlations was verified in several different results. Finally, it was clear that using Darcy's Law in cases where inertial effects are significant can lead to erroneous production estimates.