bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Damage Mechanisms and Skin Factor in Tight Gas Reservoirs
Authors: Bahrami Hassan , Rezaee Reza , Ostojic Jakov , Nazhat Delair , Clennell Ben 
Published: June 2011

Abstract
Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques.
The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, plugging of natural fractures by mud solid particles invasion, relative permeability reduction around wellbore as a result of filtrate invasion, liquid leak-off into the formation during fracturing operations, water blocking, skin due to wellbore breakouts, and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occurs through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures.
This study represents evaluation of different damage mechanisms in tight gas formations, and examines the factors that can have significant influence on total skin factor and well productivity. Reservoir simulation was carried out based on a typical West Australian tight gas reservoir in order to understand how well productivity is affected by each of the damage mechanisms such as natural fractures plugging, mud filtrate invasion, water blocking and perforation.
Prediction and Localisation of Erosion Prone Areas along Non-Compliant Sand Control Completions
Authors: Tovar J. , Zheng Y. , McDonald L. 
Published: June 2011

Abstract
Sandface completions such as standalone screen completions have suffered from erosion problems for many years. A significant amount of catastrophic screen failures are considered to be the result of high velocities of solid's laden hydrocarbons creating hot spot areas in the interface between the sandface and the completion. Previous researchers investigated the change in permeability of failed rock into annular gaps generated in non-compliant sand control completions and identified that packed material in this space can result in severe distortion to flow patterns and restrictions. This paper describes the development and testing process for a new methodology that allows identification of the erosion prone areas in the annular space between the sandface and the screen. Detailed investigation, supported by laboratory testing, reviewed oil and gas well conditions at the startup, during a cleanout and after hydrocarbon's production have been stabilised. Radial flow, mode of sand collapse, compaction, voidage, sand quality and formation petro-physical properties were tested and analysed using high and low pressure flow cells in order to quantify the changes in pressure drops through the collapsed rock material. The results indicated that flow rate, viscosity, voidage, grain shape and volume are the main contributors to the variations in pressure drops across failed sand material in the annular space. On the basis of these tests, a continuous (foot-by-foot) analytical model was developed that allows identification of the specific location and variation in pressure drops across the annular packed material for oil and gas wells. The model is composed of five (5) main elements; a reservoir inflow module, a fluid drag module, a grain size and volume module, a pressure drop module and an erosion prediction module. The model was tested using data from a North Sea field and the results, algorithms and field samples will be discussed and presented in detail.
The Application of Sand Jet Perforation in Multistage Hydraulic Fracturing Treatments in Volcanic Reservoir India
Authors: Aora Gaurav , Stolyorov Sergey , Gupta Anish , Purusharthy Naresh , Mathur Mohit , Singh Ratan 
Published: June 2011

Abstract
The Raageshwari gas field is a relatively deep (3000m) unconventional volcanic reservoir with a gas column in excess of 800 m. Gas from the Raageshwari field is used to generate energy for production of waxy, high-pour-point crude in the nearby Mangala, Bhagyam and Aishwariya fields (which were discovered in January 2004) in Barmer basin, Western Rajasthan, India (Figures 1, 2). The gas reservoir has inherently low permeability, and hydro-fracturing treatment is essential for optimum production from the field. A series of hydro-fracturing operations have been carried out on the field and treatments optimized over a period of time. A recent fracturing campaign implemented a shift in perforation methodology from conventional e-line perforation to peroration using sand jetting through coiled tubing. This paper discusses the challenges that had been associated with hydro-fracturing work in the field and benefits achieved with sand-jet perforation technology.
Effect of Initial HCl Concentration on the Performance of New VES Acid System
Authors: Wang Guanqun , Gomaa Ahmed M. , Nasr-El-Din Hisham A. 
Published: June 2011

Abstract
Viscoelastic surfactant (VES) based self-diverting acid system has been developed for better matrix treatment of carbonate formations. Literature survey indicates that the highly viscous fluid acts as a temporary barrier to reduce further fluid loss into the wormholes and allows complete stimulation of all treating zones. After acid treatment, the viscous fluid is broken by either formation hydrocarbons or pre-flush fluids. However, recent lab work confirmed that a significant amount of surfactant was retained inside the core even when mutual solvent was used. The present study was conducted to better understand these acid systems and determine factors that impact their viscosity build-up and performance inside the carbonate formations.
A series of coreflood tests were conducted using carbonate cores at different injection rates. Propagation of the acid, surfactant, and reaction products inside the cores was examined in detail. Samples of the core effluent were collected and the concentrations of calcium, surfactant, and acid were measured. Permeability enhancement and location of any precipitation was detected using CT scanner to the core before and after the acid injection. Material balance was conducted to determine the amount of surfactant that retained in the core.
Experimental results show that VES acid was not able to buildup pressure drop across the core when it was injected inside 70 md permeability cores at various acid concentrations and injection rates when only one fourth pore volumes was injected. At high concentration of HCl, Calcium and the surfactant propagated with the same velocity. When low concentration of HCl was employed, Calcium propagated faster. Surfactant retention is higher when the acid concentration and the injection rate were lower. This number could be up to 100%. CT scan confirmed only small and short wormhole branches at the area near the inlet and one wormhole dominated till the end with a decreasing diameter. Reaction rate and extension of wormhole decreased when lower concentration HCl was used and injected at a higher rate.
Three-Dimensional Shear Data to Design Effective Completions in Unconventional Reservoirs
Authors: Bray Jim , Menendez Eliud , Smith Charles H. 
Published: June 2011

Abstract
Unconventional reservoirs require an effective system of completion. A major difference between unconventional and conventional reservoirs is the plastic nature of the rock itself. Within a very short period of time, certain portions of the reservoir will flow, sealing off the productive mechanism and capacity of the formation. Complicating matters even more is the near universality of horizontal drilling in these reservoirs.
Dipole sonic logs have been used for many years to establish rock mechanical properties for conventional formations. The use of Young's Modulus and Poisson's ratio in frac design is well established. This same relationship exists in the unconventional world, but the complication of plasticity in the formation makes the relationship more difficult to understand. Traditional twodimensional models have not been able to adequately identify intervals of the horizontal reservoir that could maintain the fracture treatment.
The calculation of three-dimensional rock mechanical properties has been advanced as a way to overcome this difficulty. This paper presents the application of this advancement in unconventional reservoirs. This paper will also discuss the differences in two-dimensional and three-dimensional data and the effects of ignoring this information.
A Novel Stimulation Approach for Scale Control in Marrat Carbonate Reservoir - Case Studies from Joint Operations, PZ Kuwait
Authors: Al-Ghamdi Saleh , Al-Najim Abdulaziz , Bouyabes Ahmed , Al-Hadyani Fahad S , Nugraha Ikhsan , Hamid Saad 
Published: June 2011

Abstract
Carbonate scaling is one of the common problems that occur in wells producing high amount of water. The tendency of scaling escalates in mature fields. This problem becomes critical in sub-hydrostatic wells with Electrical Submersible Pumps (ESP). In such cases, the scale not only reduces the flow of fluids into the wellbore, but also causes frequent failures in downhole equipment, eventually stopping production leading to well workover. Frequent ESP failures can increase the operating costs to unacceptable levels which may eventually lead to field abandonment.
Joint Operations (Chevron and KGOC) in Partitioned Zone (PZ) faced severe scaling problems in Humma field producing from Marrat Carbonate reservoir. A thick layer of calcium carbonate scale was observed in the completion string during the workover. As a result of this scale, ESP repair and replacement frequencies increased abnormally. Also, the ESP amperage charts showed erratic behavior due to solids interference inside the pump resulting in pump failures.
A combined scale control and stimulation treatment was applied in three wells in Humma field in Joint Operations to slow down scaling tendency in the formation and tubular. These wells are producing up to 1523 BWPD averaging 28% water cut. The treatment provided effective placement of scale inhibitor in the formation while controlling any increase in water production because of stimulation. As a result, the workover frequency due to pump failures was reduced. Not only did the production improve, the amount of deferred oil was also significantly reduced resulting in direct oil gain and significant savings in operating costs.
This paper describes the lab analyses, treatment design and execution procedure, adopted for the implementation of this technique as well as the recommendations and lessons learned from the field experience.
Formation Damage and Fluid Loss Reduction due to Plastering Effect of Casing Drilling
Authors: Karimi Moji , Ghalambor Ali , Montgomery Monty , Moellendick Eric 
Published: June 2011

Abstract
The objective of this work is to investigate the influence of cuttings size in Casing Drilling to plug pores for fluid loss control, and thereby reducing formation damage. Historically, the emphasis of drilling operations has been to drill wells cheaply and quickly without much consideration for the resulting impact on well productivity. Formation damage occurs frequently and rapidly during drilling operations with potentially severe consequences. The Plastering Effect of Casing Drilling reduces solids and filtrate invasion, resulting in less skin damage and improved productivity. It also reduces formation damage due to cement filtrate by creating a gauged wellbore and proper casing/wellbore standoff.
The Casing Drilling process grinds drill cuttings as they travel up the annulus and creates a larger particle size distribution (PSD) profile than conventional drilling operations. These finer cuttings are subsequently smeared into the wellbore face by the mechanical contact of the large diameter casing with the borehole wall. The result is a very high quality, tight, thin, almost impermeable mud cake that isolates the formation from the wellbore. Evidence shows that cement binds very well to this type of mud cake.
The PSD analysis determined that the smaller size and wide range of Casing Drilling cuttings make it possible for these particles to readily adhere to the wellbore; this helps seal the pore spaces of the formation and prevent further solids and filtrate invasion. Pore throats can most effectively be plugged when the cuttings are in the proper micron size range as any possible gap between the mud and cuttings PSD can be covered by adding minimal amounts of properly sized lost circulation materials.
Casing Drilling has proven to be a unique approach in mitigating formation damage due to the drilling process. One case study confirms that reservoir sections drilled with casing show enhanced productivity as much as twice the wells drilled conventionally. The Plastering Effect, as an inherent benefit of Casing Drilling, keeps the producing formation as intact as possible and reduces formation damage.
Temporary Zonal Isolation Minimizes Reservoir Damage During Workover Operations in Ecuador
Authors: Del Rio C. , Boucher A. , Salazar F. , Milne A. , Robles M. 
Published: June 2011

Abstract
In Ecuador, the principal reservoirs are subhydrostatic, with permeability ranging from 100 to 2,000 mD and significant clay content. The crude oils are prone to form emulsions in contact with completion fluids. After workover operations—pulling electric submersible pumps (ESP) or recompleting a well—it is common to lose more than 1,000 bbls of completion fluid, resulting in a 20% to 50% reduction in production.
Fluid loss control pills containing sized particulate, such as calcium carbonate or sized salt, are frequently used to control the fluid loss; however, a further treatment is required to remove the solids. Using this technique, 25 wells producing a total of 8,000 BPD were worked over, after which the production decreased to 5,000 BPD.
The main challenges in developing a solids-free fluid loss control pill to control losses of completion fluid during a well intervention are: a) the low, subhydrostatic (0.16 to 0.36 psi/ft.) reservoir pressure, b) high matrix permeability, and c) cleanup when well is put on production. To overcome this, a highly viscous, polymer crosslinked fluid with an internal breaker was developed to temporarily isolate the reservoirs. Using this fluid, it is possible to work over a well without losing fluid into the reservoirs and having the associated loss of production.
In 15 wells worked over using the fluid loss control fluid combined with modified workover procedures, fluid losses were controlled and production was maintained after the workovers. This technique also made it possible to selectively stimulate certain intervals, increasing production. The total production prior to the interventions was 7,300 bpd. Afterward, it increased 27% to 9,250 bpd.
The fluid-loss control fluid, together with the new workover procedures, has now been adopted as a standard. It has proved an effective means to protect the subhydrostatic reservoirs in mature fields during workover interventions.
Increasing Oil Production without Increasing Water Cut in Wells in Ecuador
Authors: Boucher A. , Del Rio C. , Salazar F. , Milne A. , Robles M. 
Published: June 2011

Abstract
An operator in Ecuador produces from the Napo "U" sandstone formation with permeability ranging from 90 to 2,000 mD. A lateral aquifer supports the oil production coming from this zone. Water breakthrough in this formation is common in intervals with high permeability streaks causing the water cut to increase substantially, thus affecting the oil producing zones. Besides the onset of water, additional oil decline results from high pressure drawdown and high clay content (including kaolinite) in the formation. The primary damage mechanism is identified as fines migration, a common problem in wells in Ecuador.
The main challenge is to increase oil production through stimulation in wells with high water cut and a strong aquifer, without increasing the water cut. A treatment was proposed that would remove the damage in the intervals producing oil and "good" water without stimulating the interval where water had already broken through. It consisted of combining a modified organic clay acid (OCA) and a viscous disproportionate permeability modifier (VDPM) to maximize zonal coverage and minimize water production.
The first stimulation treatment using the modified OCA and the VDPM enabled the treatment to be diverted to the intervals where water had not broken through. Post-treatment results showed production had doubled and water cut remained the same as it was pre-treatment. Production then remained stable after more than 3 months. A nodal analysis model predicted that the well had a skin of approximately 10 prior to the treatment, and this skin was reduced to nearly zero following the treatment.
A subsequent stimulation treatment performed in a horizontal openhole completion using coiled tubing increased oil production by more than ten times the initial production. It was not known where in the openhole the water breakthrough had occurred in this well, but through the use of the VDPM, the water cut was reduced.
An additional 13 wells with similar damage have been treated successfully using the same fluids resulting in an additional 2,100 BOPD of production. The combination of effective diversion, conformance control and modified OCA is an effective means of selectively increasing oil production in mature fields without increasing the water cut.
In-Depth Water Diversion Using Sodium Silicate on Snorre - Factors Controlling In-Depth Placement
Authors: Stavland A. , Jonsbråten H. C. , Vikane O. , Skrettingland K. , Fischer H. 
Published: June 2011

Abstract
The waterflood sweep efficiency can be increased considerably by in-depth placement of a blocking agent. Sodium silicate is one of the few PLONOR chemicals applicable for water control. This paper highlights key results obtained from a research program on qualifying sodium silicate for offshore applications. The main findings of this work can be summarized as follows: Sodium silicate is an alkaline liquid containing nano-size particles with water-like viscosity and good buffer capacity.Sodium silicate should be diluted in brines with a low divalent ion concentration addressing the need of a sufficiently large preflush.Upon reaction, triggered by an activator, sodium silicate forms silicate aggregates and gel which reduce rock permeability.The reaction rate is controlled by the formation temperature and sodium silicate concentrations.The flow behaviour of reacted silicate aggregates is understood by the classical theory on fine particle transport through porous medium, which includes a velocity-dependent deposition rate.Coreflood experiments at high flow rates demonstrated both a good injectivity of non-reacted sodium silicate and dynamic reaction rates similar to bulk reaction rates. At low injection rates, the plugging time decreased and was explained by fines particle transport which increased the deposistion rate of silicate.Interpretations of coreflood experiments unfold the effect of cation exchange.
It is concluded that large volumes of sodium silicate can be injected into offshore oil reservoirs. Prior to the injection, a preflush is needed and the silicate is to be diluted in desalinated water. The permeability reduction can be obtained either during dynamic injection or shut-in period. The design parameters involve temperature, velocity and concentration gradients.
Fingerprint of Mud Losses into Natural or Induced Fractures
Authors: Majidi R. , Miska S. Z. , Zhang Jianguo 
Published: June 2011

Abstract
Lost circulation in fractured formations is one of the drilling's biggest expenses in terms of non-productive time (NPT), unit mud cost and safety issues. The severity and persistence of losses are to a large extent determined by the type of formation into which the fluid is being lost. It is imperative to identify whether the losses are to natural or induced fractures as losses into naturally fractured rocks require different treatments than those into drilling induced fractures. One way of identifying the type of the fracture is by image logs which are very local and limited to conductive muds, so still in their infancy and have yet to gain wide acceptance. An alternative way is possible by looking into flow behavior of mud losses (flow in/out) and associated downhole pressure response (PWD data).
This work presents an analytical formulation describing mud losses in drilling induced fractures based on which the volume and rate of losses in an induced fracture are quantified in terms of fluid properties, fracture parameters and operational conditions. Comparison between the predicted mud losses into induced and natural fractures indicates that much higher pressure sensitivity is anticipated during mud losses into induced fractures. Hence, the pressure sensitivity analysis can be used as a means to distinguish between the losses into natural and induced fractures. Once the fracture type is identified, the fracture parameters (hydraulic width or compliance) can be estimated by analyzing mud loss data. As the outcome of this study, guidelines are provided for the best practices to be used for prevention and control of lost circulation.
Gravel Packing Depleted Reservoirs
Authors: El-Dabi Fady , Bulgachev Roman 
Published: June 2011

Abstract
Gravel packing, being one of the most reliable and robust downhole sand control techniques, is often the preferred method for establishing sand control. In reservoirs where the pressure has fallen below the water gradient, gravel placement using water based fluid will produce a high overbalance leading to excessive losses of fluid that might deeply invade the formation, cause premature bridging, and fracture the formation. The main focus of this paper is to identify fluids and techniques for gravel packing a depleted reservoir and evaluate the best technique and a fluids package for a candidate well.
A well candidate in the Mediterranean is planned to be completed with cased hole gravel pack and it is a twin of a cased and perforated gas well that started producing formation sand after 4 years of production. Continued production from the reservoir is expected to drive down the pressure to 7.5ppg by the time, when candidate well is completed.
Several techniques for gravel packing a depleted reservoir have been considered which included diesel, alcohol-, oil-, gas- and water-based fluids. However after extensive lab testing the most suitable fluids package for the well was found to be conventional water packing. Contrary to expectation, formation damage tests indicated that water based gravel packing caused less damage than non-viscous oil based fluids for this particular candidate well. Solids-free high-temperature perforation kill pill and breaker package were also designed for the well to be stable for up to 4 days, which pushed the limits of solids free kill pills currently available in the industry.
The paper will discuss in detail the gravel packing fluid package selection methodology, and completion fluid, gravel pack fluid, kill pill and breaker fluids package design and evaluation for the candidate well.