bluuebunny/crossref_metadata_2025 huggingface dataset:
Key Environmental Performance Indicators in Drilling Operations
Authors: Paulsen J. E. , Saasen A. , Jensen B. , Grinrød M.
Published: December 2007

There is a trend in performance reporting within the oil and gas (O&G) industry that gains increased importance. External stakeholders with different motives have put increased pressure on the O&G industry asking for data that facilitate audit of an O&G operator’s ability to deliver sound environmental performance. Following this the question of relevant performance indicators emerges. This paper presents documentation on how a holistic approach to performance planning and measurement in drilling operations helped develop practices that resulted in improved cost-effectiveness and less environmental burden. Key performance indicators were used extensively for trend-analysis and management purpose. The methodology used rests on transparency, commitment from all involved personnel, and meets the need for better performance reporting routines for a drilling operator. Waste is one of several Key Environmental Performance Indicators (KEPIs) that aspire to be included in forthcoming common global reporting routines in drilling operations. The approach used in this case, Total Fluid Management (TFM), addresses all aspects of drilling efficiency and waste generation in drilling operations, to resolve a holistic compromise that is considered to be a sustainable practice.

Data collected through a period of 20 months after implementation of the TFM is presented. The data substantiates that costs associated with drilling and completion fluids and associated waste generated have been reduced significantly compared to the period before the implementation of the concept. The environmental load has been reduced accordingly. All benefits have been achieved without compromising the profit of the fluid suppliers. The holistic approach in planning facilitated this mutual beneficial outcome. It is argued that the model is progressive to the extent that it challenges current practice and forces the contracting industry to think and plan differently. It is claimed that the data acquisition methodology and the reporting format of the TFM allow transparency for external audit purposes
Intelligent Internal Gas Injection Wells Revitalise Mature S.W. Ampa Field
Authors: Lau Hon Chung , Deutman Robert , Al-Sikaiti Salim , Adimora Victor
Published: December 2007

In February 2000 BSP drilled and completed its first internal gas injector in the SW Ampa Block 11 field. Well SWA-285 causes deliberate crossflow of gas from the deep AW/AX gas reservoirs into the gas caps of the overlying AV oil reservoirs (Fig 1). The result is a pressure maintenance scheme that does not require any surface facilities. New production technologies employed (including long openhole gravel pack, surface-controlled interval control and lubricator valves and permanent downhole gauges) allow both control and monitoring of the downhole gas injection scheme. After 17 months of injection, the increase in AV reservoir pressure recorded in a number of observation wells and the favorable production from downdip wells in both easten and western flanks have confirmed that the internal gas injection is yielding the desired results. As a consequence of these encouraging results, a downdip horizontal well was recently drilled to capture the benefits of the first internal gas injector. In addition, a second internal gas injection was recently drilled in an adjacent block (Fig 2).
Minimizing Formation Damage with a Reversible Invert Emulsion Drill-In Fluid
Authors: Green T. C. , Headley J. A. , Scott P. D. , Brady S. D. , Haynes L. L. , Pardo C. W. , Dick Mark
Published: December 2007

A reversible emulsion drill-in fluid can exhibit the drilling benefits of conventional oil-based emulsion muds and still show cleanup characteristics equivalent to or better than biopolymer calcium carbonate water-based drill-in fluids. After exposure to the reversible emulsion drill-in fluid and an acid cleanup procedure, laboratory tests have demonstrated satisfactory retained permeabilities through sandstone cores in both the production and injection directions. Tests on aloxite disks show that the reversible invert emulsion filter cakes are stable during displacement of the drill-in fluid with brine. Clean up of the filter cakes shows that the destruction of the reversible invert emulsion filter cake containing calcium carbonate is easily attained with acid treatment through a simulated gravel pack.

The reversible emulsion drill-in fluid had higher retained permeabilities in both the injection and production directions when compared to the xanthan-based calcium carbonate fluids. The cleanup treatments for the reversible emulsion fluid and the xanthan carbonate fluids varied from a 10% acetic acid solution to a 10% hydrochloric acid solution. Tests of the reversible invert emulsion drill-in fluid filtercake stability on aloxite disks in a stirred filtration cell showed that the filter cakes are quite stable to calcium chloride displacement brine. Placement of gravel packing sand over the filter cakes and subsequent clean up of the filter cakes through the gravel pack showed that good clean up of the cakes could be achieved through the pack.

Lab work presented here has been validated by application of this reversible emulsion drill-in fluid in West Africa, where both production and injection wells have exceeded what was expected from use of a conventional invert emulsion. In addition, the wells were completed with less rig time and lower cost for the completion and clean up.
Use of Corrugated Material Technology to Provide Low-Risk Solution to Repair Connector Leakage on the Captain Field, UKCS
Authors: Smalley Michael T. , Rae Graeme , Heiskell Wes
Published: December 2007

The Worlds’ first successful installation of a newly developed Thru Restriction Expandable Internal Casing Patch (TRECP) system has been completed in the North Sea in Texaco's’ Captain Field. This TRECP system uses expandable liner technology to provide a hydrostatic seal for casing connectors, couplings and perforations. The system incorporates a corrugated liner capable of being run through a restriction and then smoothed out to a larger diameter in the casing or riser, using a cone and a hydraulically expanded collet. As a result, the overall process of creating the sealed area is simplified and the associated risk minimised. The TRECP was used successfully to isolate a leak in the squinch connector due to an ‘O’ ring failure.

In this paper, the authors will discuss the development and testing of the Thru Restriction Expandable Casing Patch and present an engineering explanation and operational description of the system. They will outline the original requirement for the TRECP, how the system was installed and operated, including the difficulties encountered, how wear on the TRECP was addressed, and how lessons learned from the first installation are being applied to improve the performance and process in future applications. The authors will also explain how the service company and operators worked together to finance this TRECP system such that it could be proven in a low cost, low risk environment prior to application in very high cost, high risk, environments.
First High Pressure, High Angle Well in Kuwait: Case Study of WMN-2
Authors: Al-Saeedi M. , Munger R. , Tooms P. , Al-Mutairi B. , Al-Quraini K. , Decaire J. , Tuncer T.
Published: December 2007

Drilling high angle wells into a heavily fractured, highly pressured, sour Jurassic reservoir may be the key to unlocking substantial reserves of light oil for Kuwait. One of the main risks to effectively developing this unconventional reservoir is the ability of wells to access a permeable, interconnected, vertical fracture network, without which the oil will not flow. Less than 50% of the vertical wells drilled to date have been successful due to a failure to intersect fractures or due to formation damage suffered during drilling. High angle or horizontal wells, while more technically challenging and expensive, will ensure fractures are encountered and will ideally penetrate multiple large, oil bearing fractures, to provide high productivity and reserves recovery per well. This paper discusses the challenges of designing a high angle well into the Jurassic which has so far proved difficult to drill vertically. These challenges can broadly be divided into three major categories - the high pressure nature of the well, the directional challenges imposed by the high angle in the reservoir, and the metallurgy aspects of operating in a highly corrosive environment.

The approach to coping with the high pressures (12,500 psi at 12,500 ft) has been to combine local experience with some of the learning from other parts of the world, notably HPHT drilling in the North Sea. The prediction of a pressure window in which to operate without gains or losses has been generated by analyzing local offset data. The task of staying within that window is crucial to being able to cross open fractures and was aided by utilizing the latest drilling technologies such as Pressure While Drilling (PWD).

Directional planning again builds on local knowledge to evaluate different options for achieving the objectives of the well. The latest tools and technologies was required to meet some demanding angle build rates in the lower part of the well in hard rock and through large open fractures. Experience gained in other parts of the world was used as the basis for design since there is no prior application of the technologies in Kuwait.

The presence of high concentrations of H2S and CO2 (5,000 – 20,000 ppm & 10,000 ppm respectively) at high pressure has made the metallurgy design a task of finding a way to resolve the conflicts between designing for high pressures, longevity, high levels of H2S and staying at reasonable cost. The final design has achieved a satisfactory balance by using risk assessment to minimize the use of expensive alloys.

This was the first well of its kind in Kuwait and could pave the way for the exploitation of a very substantial volume of light crude oil.
Innovative Well Completions in Gulf of Suez Fields, Egypt
Authors: Fotouh Mahmoud Aboul , Gutleber D.
Published: December 2007

Drilling and completing wells quite often encounter unexpected events during routine operations. Troubles occur that many times are easy to resolve while other times are more difficult and can completely turn the plan upside-down. Adapting the course of action to still meet well objectives involves many factors and individuals, incorporating innovative techniques and new technologies without compromising safety or environmental implications. This paper will discuss four case histories, which are examples of how well completion programs were modified due to unexpected events in order to salvage the well’s production potential. Coordinated teamwork between drilling, production, reservoir, and geoscience personnel to establish a revised plan in a timely manner, responding to operation/reservoir complications, is the key to success. Some of these creative alternatives were derived based upon specific well characteristics and are uncommon in normal operations. However, by sharing these techniques, others may be able to benefit from GUPCO’s key learning’s and respond to complications in their own operations.
New Incentive Contract Achieves Improved Performance in Oman
Authors: Roes V. C. , Hopkins C. J. , Young T.
Published: December 2007

Incentive contracts for drilling rigs and services traditionally follow a "beat the curve" approach aimed at reducing well durations. This method failed to achieve breakthrough performance with the PDO Deep Oil and Gas exploration drilling team in Oman. By developing a strategy that approached the supply of drilling goods and services using a team approach, and implementing an incentive scheme to reward the team as a whole rather than individual contractors, a significant improvement in performance was achieved. Exploration drilling costs were demonstrated to be reduced by 32% over the first two years of contract inception, resulting in significant savings for PDO and improved goods and services from the service contractors.
Risk Mitigation Technique for Advanced Rig Control Systems
Authors: Murray D. , Montgomery D. , Florence F.
Published: December 2007

An advanced rig control system that was provided to a major international land drilling contractor streamlines the ergonomic tasks that are routinely performed by a driller. The system employs joystick controls from a specially designed console with touch-screen displays that eliminate conventional SCR and drawworks control panels. Signals are routed though industrial grade computers and robust programmable logic controllers (PLC) to integrate data and control to simplify the correct operation of the rig. An electronic automatic driller is used to optimize drill line payout with up to four selectable constraints chosen by the driller and/or drilling engineer.

Maintenance of the software can be achieved from a remote command station via a telephone or satellite connection. The PLC and user interface software code can be monitored and modified if necessary. Using a data logger that records and transmits PLC parameters, the system designers can verify that the driller is using the system as intended.

While this remote connectivity provides high system reliability, it can increase operating risk unless proper procedures are followed. This paper identifies the risk factors and recommends specific policies to mitigate these risks. Specific examples are cited where the software on a working rig was modified from a remote site.
Lessons Learned from Acid Pickle Treatments of Deep/Sour Gas Wells
Authors: Nasr-El-Din H. A. , Al-Mutairi S. H. , Al-Driweesh S. M.
Published: December 2007

Pickle treatments are commonly conducted to remove various contaminants from the wellbore prior to performing chemical treatments in various wells. Introduction of these contaminants into the formation during the treatment can cause loss of well performance, especially in tight formations. These treatments should be designed to remove various contaminants from well tubulars in an efficient and cost effective way.

A pickle treatment was designed to clean well tubulars in several wells prior to performing acid fracturing in the carbonate formation. The pickle treatment consisted of several fluids such that each fluid removed one type of contaminants. This paper examines the effects of fluid composition, volume, and placement (bullheading versus coiled tubing) on the efficiency of pickling treatments. More than twenty pickle treatments performed on deep, sour, hot gas wells were examined.

To assess pickle treatments in the field, spent acid was analyzed and the concentrations of key ions were measured. Sufficient measurements were made to obtain concentration profiles of chemical species in the spent pickle acid. These profiles were numerically integrated and the data were used to assess the outcome of each pickle treatment. In addition, particulate solids present in the spent acid were separated and analyzed using XRD and XRF techniques.

Pickle treatments were conducted on more than twenty gas wells. Some of these wells were perforated, while others were not perforated. Un-perforated wells were pickled using 1.75" high-pressure coiled tubing. On the other hand, perforated wells were pickled using bullheading. The pickle treatments consisted of slugs of surfactants, organic solvents, hydrochloric acid and gelled fluids. Samples of all pumped fluids were collected and analyzed. In addition, well flow back samples were collected every two minutes and were also analyzed to determine their composition.

Analysis of spent acids indicated that the major tubular contaminants are mill scale and pipe dope. Spent acid samples collected from deep sour gas wells contained up to nearly 105,500 mg/L of total iron. The efficiency of removing pipe dope was followed by tracing the concentration of zinc, the main acid-soluble constituent in the pipe dope, in the spent acid. The concentrations of acid and iron were used to determine acid reaction with the corrosion products present in the tubing. The concentration of the chloride ions was used to determine the dispersion and mixing behaviour of the acid slug.

This paper presents the results obtained from analyzing more than 2000 samples obtained from twenty treatments. The results of this work have been used to enhance the efficiency of the pickle treatments and to significantly reduce the treatment cost.
Modified Synthetic-Based Reservoir Drill-In Fluid: Eliminating the Need for Costly Synthetic Displacements
Authors: Luyster M. R. , Sketchler B. C. , Ali S. A. , Foxenberg W. E. , Dick M.
Published: December 2007

A number of technical advances in the design and engineering of oil- and synthetic-based reservoir drill-in fluid (RDF) systems have taken place in recent years. This includes modifications to the emulsion/wetting package, type and size of the bridging/weighting material and displacement techniques. This paper presents laboratory analyses and subsequent field application of a newly formulated RDF compatible with a sand-control-screen completion.

Through laboratory testing, an emulsification package was identified that would enhance filtercake lift-off. Next, a pilot yard test was performed utilizing a desilter to optimize the D50 of the bridging/weighting material. A unique combination of nozzle, hydroclone and pump pressure was utilized as the combination of these three variables yielded a D50 of less than half the original D50. Laboratory tests confirmed that a filter cake deposited by this modified synthetic-based RDF could effectively "flow" through a selected sand-control screen.

The authors also show how the combination of specifically sized weighting/bridging material, the emulsification/wetting package, and custom completion practice to run the premium sand-control screen eliminated the need for a costly solvent-based displacement. In addition, production data from the subsequent Gulf of Mexico horizontal completion that successfully utilized this technique will be provided.
Productivity Preservation via Hydraulic Propped Fractures in the Eldfisk North Sea Chalk Field
Authors: Cook C. C. , Brekke K.
Published: December 2007

The Eldfisk oil field is a high porosity, low permeability reservoir of soft chalk in the Norwegian North Sea. Commercial oil production from the Eldfisk field is dependent on well stimulations involving hydraulic fractures. To date, pseudo limited entry (PLE) acid fracturing has been the standard completion technique that initiates relatively high (5000 bopd) individual well oil production rates. Over time however, many of the Eldfisk wells have experienced rapidly declining oil production. The main causes of the decreased well productivity are attributed to hydraulic fracture closure, solids production and casing collapse. Initial calculated skin values of–4.5 on average increase annually at a rate of +0.6. Through year 1999 over 100 casing deformations have been logged in the reservoir. The root problem behind the productivity deteriorations is the Eldfisk field soft chalk nature where the Brinell Hardness Number (BHN) is commonly less than 5 for the most productive zones. In late 1997, an alternative completion technique involving four hydraulic propped fractures was successfully executed in a horizontal well. Evaluation of rate-time flow efficiency for the propped fractured well versus acid fractured wells with the use of an analytical model is reported in this paper. In addition, the analytical model is used to run predictions of increased multiple propped fractures. This paper relates formation BHN to the hydraulic fracture design criteria and concludes that productivity for hydraulic propped fractured wells in soft chalk formations is preserved over time to a greater extent versus the current standard PLE acid fracture technique. This paper concludes that an additional horizontal well with eight hydraulic propped fractured zones is warranted to improve understanding of the cost effectiveness of this alternative oil recovery completion technique for the Eldfisk chalk field.
Asphaltic Crudes and High Density Brines: A Potentially Lethal Combination
Authors: Luyster Mark R. , Hebert Paul , Ali Syed A. , Kippie David P. , Carboni John A.
Published: December 2007

The use of high density brines in well completions and/or recompletions poses potential problems for initial well production. Emulsions may be formed when the crude and completion brine are commingled under high shear at points such as the perforations, well-head, chokes and valves. This commingling can lead to the production of very stable viscous brine-in-crude emulsions. Resolving emulsions can be a costly operational problem, especially in sub-sea completions. With heavy or asphaltene bearing crudes, the prevention of emulsions is even more challenging. The resulting emulsion may likely be stabilized by asphaltene precipitates. This can lead to very viscous and tight pads. These emulsions and/or pads can yield a multitude of operational problems that include: increased shorting in the separators, tripping of equipment, costly clean-up/disposal, and increased completion delays/costs.

This paper describes laboratory analyses that were utilized to evaluate six (6) emulsion preventers to prevent a potential asphaltene-stabilized emulsion. Crude recovered from well tests in a recent Gulf of Mexico deep-water discovery were analyzed for composition. These crude samples were then commingled with high-density completion brine that was treated with various concentrations of selected emulsion preventers. The results were evaluated for clarity, presence of a pad, coalescence, and emulsion tendency.

Emulsion preventers are specialized chemicals that rely on a soluble carrier. They must be brine soluble and this alone may pose a challenge in high-density brines. They must remain in the brine phase under downhole conditions and present themselves at the crude-brine interface, thereby, initiating the coalescence process.

To simulate downhole conditions as near as possible, iron was introduced into the completion brine at various concentrations. Iron alone can cause and/or augment the severity of an emulsion. In some cases, reverse emulsions were evident. All emulsion preventers were tested in the presence of iron as a final evaluation of their performance.

This study allowed the authors to introduce a new emulsion preventer for use with high-density completion brine. This non-emulsifier was utilized in four (4) recent deep-water sub-sea completions in the Gulf of Mexico and yielded favorable results. The field case histories are presented to substantiate the laboratory findings. An additional benefit derived from this study was a more efficient and rapid well clean-up after the initial completions with no system upsets.
Modelling of Both Near-Wellbore Damage and Natural Cleanup of Horizontal Wells Drilled With a Water-Based Mud
Authors: Ding Y. , Longeron D. , Renard G. , Audibert A.
Published: December 2007

Prediction of formation damage that occurs in horizontal wells, often open hole completed, is a critical point for optimising an oil field development. The economic impact of near wellbore induced drilling-damage and cleanup efficiency has led to make significant progress in both experimental and numerical studies in order to assess the wellbore flow properties during oil production.

There is a fundamental difference between water-based and oil-based mud invasions. In an oil-bearing formation, the displacement of the oil in place with an oil-based mud (OBM) filtrate is a miscible displacement process, while the displacement with a water-based mud (WBM) filtrate is a two-phase flow process (imbibition), generating high wetting phase saturations in the invaded zone. Then, during oil back flow, a portion of the wetting phase is trapped, leading to residual wetting phase saturations greater than the initial ones. Even in the absence of chemical interactions between filtrate and fluids in place, this induces an adverse water/oil relative permeability effect, which is an additional permeability impairment. In a previous paper, a methodology combining both experimental and numerical approach was presented to evaluate the natural cleanup of horizontal wells drilled with an oil-based mud (OBM). This paper presents an extension of the methodology for simulating both i) near wellbore invasion and permeability damage generated with a water-based mud (WBM), and ii) natural cleanup during oil back flow when the well is put under production.

This paper describes a numerical approach to model the formation damage with WBM and predict well performance for natural clean up when the well is subject to a pressure drawdown. The kinetics of mud filtrate invasion, the filter cake properties and the filtrate/oil relative permeability curves in imbibition and drainage, together with damaged and return permeabilities are obtained from specific mud damage laboratory tests. Using these data, the mud filtrate invasion during the drilling phase is simulated, leading to a cone-type invasion depth along the horizontal well. This approach has allowed us to study the impact of various parameters related to fluids or cake properties, drilling conditions and natural cleanup process on the well performance.
Quantitative Analysis of Mechanisms for Water-Related Sand Production
Authors: Han G. , Dusseault M. B.
Published: December 2007

It is well known that saturation changes of the rock-wetting phase or alterations in wetness can lead to sand instability, therefore sand production. Several possible mechanisms are discussed in the paper, among which chemical reactions between water and sand and the changes of capillary force as a part of cohesive strength are focused upon quantitatively.

Based on the time frame of sand production record, four major possible chemical reactions between reservoir sand and formation water are identified and analyzed, including quartz hydrolysis, carbonate dissolution, ferruginous deposits and clay swelling. Those reactions increase sand instability either through altering the surface energy of the sand and physically changing the shape and size of cement, (known as Rebinder effect), or locally increasing the pressure gradient. The possibility to quantify the effects of those reactions is discussed and the main difficulties are pointed out.

Resorting to an analytical model at the grain scale, which accounts for meniscus behavior and properties in two-phase liquid systems and expresses the results in terms of capillary bond force and a tensile strength in a Mohr-Coulomb plot, the manner and magnitude of the capillary force influence on sand stability after water breakthrough are quantitatively described. It is found that, at grain scale level, the capillary cohesive force is one to three orders higher than the destabilizing seepage force from fluid pressure gradient, depending on particle sizes. Therefore it should not be neglected in the analysis of sand instability. Furthermore surface tension of fluids is found to be linearly related to capillary bond force and therefore to rock strength (tensile strength or UCS), the magnitude of which highly depends on the sand particle size, especially when particles are small. The model is able to successfully explain many reported phenomena about both capillary force and water-related sand production.

As a conclusion, changes of capillary force with water saturation may have more influence on sand failure than chemical reactions in weakly consolidated sandstone at the beginning of water breakthrough. After some critical water saturation, the capillary strength diminishes and chemical reactions may become dominant over time.
Coupled Reservoir-Geomechanics Model with Sand Erosion for Sand Rate and Enhanced Production Prediction
Authors: Wang Yarlong , Xue Shifeng
Published: December 2007

A fully coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena both in heavy-oil reservoirs (i.e. Northwestern Canada) and conventional oil reservoirs (i.e. North Sea). The model is implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. A sand erosion model is postulated after the onset of sand production, which is determined based on the degree of plastic deformation inside the reservoir formation calculated by the coupled reservoir-geomechanics model. Both the enhanced production and the ranges of the enhanced or sanding zone are calculated, the effect of solid production on oil recovery and enhancement are analyzed. Field data for solid production and enhanced oil production from Frog Lake (Lloydminster, Canada) are used to validate the model for the sand rate and sand production. Our studies indicate that the enhanced oil production can be contributed by either (1) the a large-scale reservoir formation mobility improvement, (i.e. wormhole type model), by (2) a higher fluid velocity due to the movement of the sand particles according to the modified Darcy's flow, or by (3) an effective well radius increase or negative skin development due to sand erosion if formation does not permit an extensive erosional zone. Such an improvement on productivity reduces the near well pressure gradient so that the sanding potential is weakened, but permits an easier path for oil to flow into the well due to an enhanced permeability. Two-phase flow can affect pressure gradient and formation residual cohesion due to capillary pressure buildup. Indirectly, production enhancement strategy can be controlled by the water saturation distribution and development, as the success and economic value of a field operation can depend on if sand production can be induced or not. Such an analogy can also be used for a completion strategy by allowing a certain amount of sand production before gravel pack in high flow-rate reservoir.
A Numerical Model to Study the Formation Damage by Rock Deformation from Well Test Analysis
Authors: Osorio Jose Gildardo , Wills Alejandro , Alcalde Osmar Rene
Published: December 2007

In oil/gas reservoirs, the state of stress changes as fluid production/injection from/into the reservoir takes place. Also, petrophysical and geomechanical properties may change due to the variation of the effective stress. However, this consideration is seldom taken into account in well test analysis.

This paper presents a numerical, fully coupled, fluid- flow/geomechanical model to perform well test analysis in stress-sensitive reservoirs. The governing equations are developed in cylindrical coordinates honoring the geometry of the flow lines characterizing the drainage area in most well tests. The model is a 3D, point distributed, finite-difference simulator which applies a fully implicit discretization scheme to ensure maximum stability.

The model assumes isothermal, single-phase fluid-flow (slightly compressible fluid). Infinite and finite acting behavior is allowed during the well test. Reservoir properties are allowed to change from one layer to another. Both cases isotropic and anisotropic rock property behaviors are considered in the model. The rock behaves as elastic system whose deformation is described by nonlinear theory (the mechanical properties are function of the mean effective stress).

The results show that in stress-sensitive reservoirs the permeability decreases with production time reaching its minimum value near the wellbore and moving more and more into the reservoir as production time increases. After a certain production time, the permeability distribution reaches a constant value. An important finding from this study is that the damage caused by rock deformation is irreversible; therefore, its early detection and treatment is essential for optimum reservoir management.
Optimization of Matrix Acidization by Elementary Capture Spectroscopy Log
Authors: Mohamad Natsir , Defrian Basya S. , Kusaka Koji , Simatupang Johnson
Published: December 2007

Beringin field D-structure (Beringin-D) is located in South Sumatra, Indonesia, operated by Perusahaan Pertamnabgan Minyak dan Gas Bumi Negara (Pertamina), DOH Prabumulih. Since its discovery in 1987, some 30 wells have been drilled and current total oil production is approximately 1,700 BOPD. The geological structure of this field is homocline with several faults across the field and several late Oligocene/early Miocene hydrocarbon-bearing sandstone layers are deposited on basement or on shale by on-lapping.

In the past, formation damage problems were encountered in Beringin-D and matrix acidization was applied to improve well productivity. However, the results were mixed and the main reason for failed acidization was thought to be lack of knowledge of clay types in the formation; thus, composition of the treatment fluid was not optimized. Therefore, to identify clay types present in the formation, an ECS* Elementary Capture Spectroscopy log was run on Well BRG-19. The ECS tool is a wireline-run neutron device that can detect important elements in openhole or in cased hole. Combined with NGS* Natural Gamma Ray Spectrometry log and other information, a comprehensive formation mineralogy analysis is possible.

Prior to obtaining the ECS/NGS logs, higher than 10% montmorillonite (smectite) concentration was assumed and sandstone acid (SSA) had been commonly used for Beringin-D wells. However, the log on BRG-19 revealed that the interval of interest contained 8% kaolinite and 3% montmorillonite. On the basis of this new finding, standard acid was used instead of the SSA, and the result showed 100% oil production improvement compared to the average 30% improvement in the past. Also, the SSA costs approximately twice as much as the standard acid.

The ECS and NGS logs helped us identify and quantify clays in situ, and we used this information to optimize matrix acidization through a field case.
Perforating System Selection for Optimum Well Inflow Performance
Authors: Folse Kent , Allin Melissa , Chow Chris , Hardesty John
Published: December 2007

Oilfield operators and service companies continually face challenges to provide completions that not only produce at optimum levels but also accelerate return on investment (ROI). These operational demands are further complicated by the fact that the range of reservoir scenarios continues to expand. In attempting to satisfy these needs, one component of the completion process is often over looked or taken for granted — the perforation process.

In the energy industry, many companies base their selection of shaped-charge perforators solely on API Section I criteria such as depth of penetration or casing-exit hole size. Other factors, such as the actual performance of given shaped charges at in situ conditions, also should be evaluated when making perforating decisions for the completion process. Focusing perforator system performance on reservoir productivity rather than on the shaped-charge performance optimized for concrete testing (which is the case with API Section I) can ultimately lead to significant improvement in well inflow performance.

Although API RP43 Section IV perforating procedures (to evaluate well perforators under in-situ conditions) have existed since 1985, there has been limited field validation of experimental results and model predictions based on these procedures.1-3 This paper discusses insights gained from a series of Section IV tests conducted with Berea and Castlegate sandstone cores under varying in situ conditions. The Section IV lab experiments represent physical models of the near-wellbore region during perforation and completion processes under in-situ stress. The results of these experiments indicate that understanding the inherent system inadequacies and experimental conditions is critical to proper integration of the results with theoretical models and field data.
Application of a Novel, High-Density, Brine-Based, Biopolymer-Free Reservoir Drilling Fluid: A Case Study
Authors: Knox David , Bye Gry Kristvik , Horton Robert , Svoboda Charlie , Foxenberg William , Tresco Kim
Published: December 2007

Low-solids, brine-based reservoir drilling fluids are widely accepted as being beneficial with respect te a rheological profile suitable for high performance reservoir drillto minimising fluid-related formation damage and optimising compatibility with the completion design. Traditionally, the maximum density attainable with a low solids fluid has been limited – either due to the prohibitively high cost of the base brine required, or the poor performance of viscosifying biopolymers in a divalent cation environment.

A reservoir drilling fluid has been developed that exhibits unusually high quality rheological behaviour in high-density calcium- and zinc-based brines, without the aid of a biopolymer.

The first field trial of this fluid was on the reservoir section of well 34/10 I-1-AH, in the Gulfaks Satellites Development in the Norwegian Sector of the North Sea. Fluid properties during the pre-testing, mixing, drilling and completion of this section are detailed in this paper.
Formate Brines: A Comprehensive Evaluation of Their Formation Damage Control Properties Under Realistic Reservoir Conditions
Authors: Byrne Michael , Patey Ian , George Liz , Downs John , Turner Jim
Published: December 2007

Monovalent formate brines were first introduced into the oilfield environment in the early-1990's, in response to the industry demand for better drilling and completion fluids to meet the increasingly complex technical challenges posed by modern well construction practices.

After years of rigorous field-testing, in a variety of demanding well construction operations, the formate brines are now acknowledged to be probably the best foundation for any modern high performance drilling and completion fluid. The formate brines are currently having their greatest impact as the primary components of HT/HP reservoir drilling and completion fluid formulations.

A number of field and laboratory tests have indicated that when formate-based formulations are used as reservoir drilling-in and completion fluids they appear to cause less formation damage than some other conventional fluid formulations, and consequently they are often seen to have a beneficial effect on well productivity. Up until now, however, little of this important information has found its way into the public domain.

It has been common practice for a number of the major multinational oil companies to contract a specialist formation damage prediction company to carry out laboratory-scale formation damage tests with formate brines before using these fluids in their well constructions operations. This paper draws together the results of a significant number of these tests carried out by the specialist laboratory using formate-based fluids passed through real reservoir core materials for realistic time periods and under realistic reservoir conditions.

As well as providing a unique insight into the interaction between formate brines and a range of reservoir core materials and reservoir fluid types under simulated downhole conditions, this paper also outlines the methodology developed to ensure that the formation damage tests carried out with formate brines are not influenced by laboratory artefacts.

The conclusion of the paper is that a significant number of laboratory results, obtained under test conditions closely simulating reservoir conditions, tend to lend support to the growing perception that formate brines have valuable formation damage control properties that can be exploited to improve we ll productivity prospects in even the most demanding environments.
Filtration Properties of Oil-in-Water Emulsions containing Solids
Authors: Kassim Al-Riyamy , Sharma Mukul M.
Published: December 2007

This paper is an attempt to study the mechanisms controlling the filtration and fluid leakoff properties of emulsions containing solid particles.

HPHT filtration tests clearly demonstrate that emulsions have the ability to reduce filtrate loss to the formation. However, the emulsion droplets tend to invade the formation and form an internal filter-cake. This is evident, from the lift-off pressures needed to initiate flow-back and deep invasion of emulsion droplets in long core experiments. Emulsions containing solids (CaCO3 in our case) had lower filtrate volume and higher return permeabilities than solids free fluids. The effects of percent oil, injection pressure, core permeability, temperature and viscosity of the continuous phase were investigated. Injection pressure and core permeability had major influences on the filtration properties of the emulsified completion fluids. Higher injection pressures increased internal damage and lowered the return permeability. Higher permeability cores had higher filtrate loss. Emulsion droplets were observed in the effluent and solid particles are needed to form a stable external filter-cake.

Long core experiments showed that using emulsions containing acid-soluble solid particles have 100% return permeability after an acid squeeze showing that the emulsion droplet invasion depth is less than one inch. It is shown that solids free fluids had the highest formation damage and higher lift-off pressures.

Analysis of the fluid leakoff data indicates that emulsions containing solids do not behave as classical filtration theory predicts. Due to the invasion of emulsion droplets into the formation the data did not fit the calculated filtration profiles.

Sizing the solid particles and the emulsion droplets in muds according to the permeability of the rock and the external cake is important in forming stable external filter-cakes. This increases the return permeability and results in easier cake removal (low lift-off pressures).
Use of a pH Sensitive Polymer for Conformance Control
Authors: Al-Anazi Hamoud A. , Sharma Mukul M.
Published: December 2007

A new strategy of using pH sensitive polymers for conformance control is proposed. The rheological properties of some polymers such as anionic derivatives of polyacrylic acid are shown to be very pH sensitive. For example, their viscosity varies from 5 cp at a pH of 2.5 to 20,000 cp at a pH above 6.0. This rheological behavior is reversible as the pH is cycled. Rheological data is presented at different polymer concentrations, temperatures and in solutions with different ionic strength. The effect of temperature on the rheological properties of the polymer is shown to be small. Compatibility tests showed that this polymer is compatible with most brines (NaCl, NH4Cl, and KCl).

Core flow experiments were conducted on Berea cores. The results showed that the polymer solution was easily propagated through 6 inch long cores due to its low initial viscosity (~5cp). The polymer solution formed a rigid gel inside the pores after a shut-in period of 24 hours as the pH of the fluid increased above 6. The gelled polymer was found to be stable up to the maximum examined pressure gradients of 4000 psi /ft across the core. Experiments were conducted by using acid pre-flushes ahead of the polymer solution. These results indicate that the polymer can be placed deep into a formation by using pre-flushes designed for a specific rock mineralogy.

The pH sensitive polymers studied here are excellent candidates for conformance control. It may also be possible to use them for temporary zonal isolation since they can be easily broken down with a mild acid wash and flowback.
Blake Seawater Injection Well Perforation Optimization
Authors: Paveley Craig , Brown James , Edward Du , Beesley Martin , Patey Ian , Byrne Michael
Published: December 2007

The Blake field, in the Outer Moray Firth, UKCS, is a shallow thin oil reservoir in the Captain sandstone formation. The initial subsea development consists of 6 production and 2 seawater injection wells tied back to the Bleoholm FPSO, 12 km away. The production wells are horizontal openhole completions with standalone sand screens whilst the injection wells are high-angle cased and perforated.

The principal keys to the successful development of Blake were the placement of the production wells relative to the oil-water and gas-oil contacts and the efficiency of the water injection scheme.

On completion and testing of the first seawater injection well, injectivity was found to be significantly less than expected and therefore had a potential material impact on the water injection strategy for the field. As a result focus was placed on understanding the key mechanisms influenceing well performance and to perform all necessary work to mitigate the effects in the second water injector. This work consisted of coreflood tests, diagnostic perforation surge flow modeling, perforation performance remodeling and well design and operational changes.

From the coreflood tests it became apparent that formation fines mobilisation and migration was a major contributor to under performance. The surge flow modelling indicated that the underbalance applied when perforating the first injection well would have induced high surge flow rates potentially causing formation damage through rapid fines mobilisation; the underbalance having been designed to optimise perforation performance.

As a result of this work the second seawater injection well was perforated with a lower underbalance set to limit the surge flow rate; this underbalance being significantly lower than the theoretical optimum required for perforation effectiveness. The initial injectivity testing on the second well has proved to be significantly better than for the first well.

The paper outlines the diagnostic coreflood testing completed and how the results were applied together with the perforation surge flow modelling and perforation operational design to establish an operational strategy to optimise seawater injectivity on Blake; including well design changes.
Successful Applications of Borate Crosslinked Fracturing Fluids at High Temperature
Authors: Wang Xiaolan , Qu Qi , McCarthy Scott , Null Jonathon , Bowen Kody , Neumann Luis Fernando
Published: December 2007

In the past when hydraulically fracturing a reservoir with a bottomhole temperature greater than 300°F (149°C), the only choice for a fracturing fluid was the transition metal crosslinked CMHPG (carboxymethyhydroxypropyl guar) system. While being labeled as a somewhat "clean" fracturing fluid system, these zirconium crosslinked systems required large volumes of gel stabilizers for long term fluid stability. Shear stability of these fluids was also not as good as the borate crosslinked guar or HPG (hydroxypropyl guar) systems used at lower temperatures. To improve the shear stability of fracturing fluids above 300°F while lowering the overall system cost to the operators, development of a borate crosslinked HPG based fracturing fluid system for use above 300°F was initiated.

This paper describes the development of a high temperature (>300°F) borate crosslinked HPG fracturing fluid system and its field applications. In the process of developing this system, a different type of gel stabilizer that is more effective than common gel stabilizers such as sodium thiosulfate and less toxic than methanol was developed and applied in this system.