Oil production in southern Mexico is mainly from deep (>16,000 ft) high-temperature (> 300°F), naturally fissured dolomitic limestone reservoirs with clays present. With increasing depth, the dolomitization increases and the porosity and permeability decrease. These reservoirs must be stimulated to produce, and treatments are traditionally repeated to maintain production. Although there is a substantial body of published research on stimulating carbonate formations, there is little on treating dolomites specifically. In general, the smaller the volume of reactive fluid required to penetrate into the formation to create a wormhole—a function of reactive fluid used, injection rate, and temperature—the more efficient the treatment. Hydrochloric acid (HCl) has both a high dissolution rate and dissolution capacity which, at high temperature, results in dissolution of the face of the formation, as opposed to wormholing, and uncontrollable corrosion rates. Organic acids have lower corrosion rates and limited dissolution capacity, but have a relatively high rate of dissolution, which also results in face dissolution at high temperature. Although, clays present in the formation may slow the rate of dissolution. Chelant-based fluids are less corrosive, have lower dissolution rates, and are capable of creating effective wormholes at temperatures up to 400”F in carbonates. Although dolomite retards the dissolution rate of both acids and chelants, the difference is less with chelants. The wormholing efficiency of chelants in dolomites is also less rate dependent than is that of inorganic acids. Acidic hydroxyethylethylenediaminetriacetic acid (HEDTA) fluids were developed to stimulate high-temperature carbonates and dolomites. These fluids have been highly effective in stimulating both carbonate, and even sandstone, formations worldwide. However, the optimum pH and injection rate for wormholing is markedly different for carbonates and dolomites. In addition, a low pH may result in emulsions and corrosion downhole or at surface when flowing back the treatment. Recent studies show that the efficiency of diammonium EDTA (DEA) with the correct pH is similar whether stimulating a high-temperature limestone or a dolomite formation, at similar injection rates. A direct comparison has been made by performing treatments in the same reservoirs using the two chelant systems. In every case, the initial post-treatment production with the DEA-based fluid has been significantly higher and the production decline slower. This is attributed to stimulating both the dolomite and limestone intervals and removing the potentially damaging clay and fines. The fluid also eliminates the possible issues with using a low-pH fluid.

Diffusion Coefficient ( D e ) is a very important parameter for the formation damage treatment job design. Commonly a Rotating Disk Apparatus (RDA) is used to obtain acid D e and reaction rate. There are two major limitations of conventional lab practices (1) The D e is obtained at 1000 psi (or below) system pressure, which is too low to represent realistic reservoir conditions. (2)The D e obtained from lab experiments are based on a fresh acid, which has been ignoring the impact of reaction products, especially CO 2 . Hence the results of D e cannot represent the real reaction kinetics between carbonate rock and injected HCl during the acid treatment. In this paper, we investigate the effects of D e of HCl acid as it reacts with both calcite and dolomite. A modified RDA is used to obtain the true spent acid reaction kinetics at reservoir conditions. In order to provide accurate reaction kinetics data that is more representative of the true reservoir conditions, a true spent acid concept is adopted here in this study. The true spent acid is formulated at reservoir condition in various spending stages. In addition, different mineralogy including calcite and dolomite are fully studied. The reaction products of CO 2 and counter ions are taken into consideration at different acid spending stages. The experimental results show that the D e of the HCl acid is much lower at high pressure than low pressure at the same concentration due to the impact of CO 2 produced by the HCl-carbonate reaction. For example, at 150 °F, the diffusion coefficient of 15% HCl at 3,000 psi reduced 50% of its original value when at 1,000 psi of 15% HCl. The diffusion coefficient of the fresh acid is much higher than the diffusion coefficient of the same acid strength of true spent acid due to the presented count ion and CO 2 in the true spent acid. The D e of HCl/calcite is two orders of magnitude higher than D e of HCl/dolomite at the same conditions (acid concentration, temperature). Conventional experimental results significantly overestimate the D e , dissolution rate and reaction rate. When the D e implemented in a job (formation damage treatment) design, those defective data could result in dramatic errors in determining the treatment fluid schedule, rate, and volume. In order to properly design the formation damage treatment jobs, the D e of acid acquired from high-pressure and various spent conditions should be used.

The key to formation damage control is minimizing the depth of contact/impact of the formation and drilling fluid by minimizing solids and liquid invasion into porous (fractured) formations. Analysis of downhole filtration conditions and particle size (distribution) measurements were used to select “fit to pore size” fluid loss control materials in order to maximize pore/fracture plugging efficiency. Further tests served to predict potential alteration of rock properties. Particle size measurements have been performed for commonly used (natural and synthetic) polymeric fluid loss and other additives dispersed in water. High-pressure Hg porosimetry was used to determine the pore size distribution of core samples. Core flow tests served to measure permeability and permeability damage caused by fluid loss additives. Spontaneous fluid absorption rate was studied using modified tensiometer and wettability of the cores were determined by ‘sitting drop’ technique. In low permeability porous (tight and shale gas) formations consisting of macro to nano pores most filtration studies are limited to provide reliable filtration data for all cases due to the fact that drilling fluids solids particle sizes relative to pore sizes. Particle size measurements of commonly used (natural and synthetic) polymeric fluid loss additives in water have provided typical size range by particle number in the 25-35 nm range, and 120-700 nm by volume. Such particles can play a significant role in internal plugging of micro to nano size pores and microfractures. Core flow/filtration tests using low permeability (<5 mD) core samples and model fluids containing fluid loss additives resulted in rapid permeability reduction (to 100%), typically in close to core face region. Results proved the achievable pore plugging efficiency and invasion control into low permeability rocks during drilling. Particle size data gained for CPG (Cloud Point Glycol) solutions proved that this system could also be used to form efficient barrier within the low permeability formation, showing certain analogy between mitigation of formation damage and wellbore instability. Better insight into downhole filtration mechanism and conditions, especially for initial filtration phase in low permeability formations can lead to designed “shallow bed” instead of practically uncontrolled “deep bed” filtration, where external filter cake is essentially not formed. Such internal pore plugging technique can be the key to the minimization of solids/liquid invasion and associated formation damage.

Carbon dioxide injection and its performance during sequestration activities rely on the ability of the injection well to inject the desired amount of CO 2 for decades. However, the CO 2 -rock-water interaction may cause immense formation damage by plugging the pores and reducing the permeability. Its severe consequences will reduce oil and gas productivity and CO 2 injectivity in the reservoir. In this study a numerical simulator is developed and it solves the fluid flow equations, chemical reactivity equations, particle transport and particles deposition equations to predict the amount of formation damage during CO 2 injection. We found that it has high rate of chemical reactivity and dissolution of reservoir rock near the wellbore. The dissoluted reservoir rock particles get precipitated in the reservoir away from the injection well, plugging the pores and reducing the formation permeability. From the simulation result on the effect of reservoir depth and temperature, we found that deep oil and gas reservoirs are good candidates for CO 2 sequestration than shallow reservoirs. Because the increased depth and temperature of a deep reservoir decrease the CO 2 dissolution rate and lower the solid precipitation. Sensitivity analysis of CO 2 injection rates was performed to identify the effect of CO 2 injection rate on reduced permeability in deep and high temperature formations. It was found that increased CO 2 injection rates and pressures enable to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO 2 at a higher rate for better pressure maintenance, no further diminution of residual oil.

The knowledge of damage profile in horizontal wells is the key to designing the appropriate treatment volume to restore or improve their productivities. The elliptical (conic) damage profile associated with horizontal well is known but review of industry-wide applications by different Operators shows no corresponding uniform correlation between the damage profile and actual treatment volumes that have been applied. The result of this inadequacy has often led to sub-optimal post stimulation performances due to either partial damage removal or formation deconsolidation as a result of little or too much acid volumes across the damaged zones that could lead to poor coverage or over-dose with attendant incomplete damage removal or secondary precipitates respectively. Funds spent on stimulating horizontal wells estimated at average of USD 0.5mln/well did not yield the expected rewards as the stimulation gains are mostly short-lived due to wrong volume design and application. The problem highlighted above led to the emergence of this engineering model based on the complete knowledge of elliptical horizontal damage profile usually associated with horizontal completions and is presented for improved stimulation solution to the removal of damage in horizontal wells. The approach offers true stimulation in cost effective manner by applying only the right acid volume in the right zone of interest. The development of the horizontal well stimulation model from the first principle and presentation of easy-to-read table and charts for specific range of well parameters (damage radius, porosity, wellbore radius and drain-hole length/diameter) versus treatment volumes, field applications guide, limitations and costs/treatment benefits are the output derivable from this innovative work. The benefit of this emerging technology includes; reduction in cost of chemical for well treatment, true stimulation of damaged near-wellbore region and improved performance, minimal contact of acid system to downhole tubular and overall cost efficiency estimated at 50% savings when compared with existing approach that uses about 200% of the required acid volume.

Due to usual higher oil and gas production, high permeable reservoirs are considered to be forgiving and to be able to hold up very well against formation damage induced by any solids and liquids, so these reservoirs have not deserved a fair share of that attention. In fact, any formation damage can inevitably alter the permeability of the porous media and adversely affect oil recovery to different degrees, and the damage is more deadly to horizontal well. Triassic reservoir with the maximum permeability of more than 2 Darcy and the maximum throat sizes of more than 100 μm in the Tarim Basin provides us with a perfect example. Horizontal well is the key technique to increase oil production in this reservoir. However, after completion, horizontal wells can not produce through natural power or gas-lift, and did not present the advantages of increasing production compared with vertical wells. The results of granularity analysis and dynamic damage evaluation experiments present that the original drill-in fluids can not protect the reservoir with permeability of more than 100 mD, while the percentage of regain permeability is less than 50%. The drilling fluids were modified by adding fibrous bridging agents instead of common spherical bridging agents to rapidly form a tight plugging zone near the wellbore that efficiently seals the large pore throats. The dynamic filtration test and the analysis of mudcake through the FEI Quanta 450 environment scanning electron microscope (ESEM) showed that the optimized drill-in fluids can form tight filter cakes, plug the pore of reservoir effectively, and enhance the percentage of regain permeability of core samples up to 90%. After the application of the new drill-in fluids, horizontal wells are in high flowing production after completion, and the wellbore quality are also improved.

Well planning in mature fields can be challenging as the more marginal reserves are targeted. Hydraulic fracture stimulation is a key technology to access multiple reservoir layers and thereby maximize recovery. However, fracture propagation in low porosity carbonates may be strongly confined because of high tensile strengths in bounding layers. The strong confinement can impede vertical fracture propagation and the ability to access reservoir units adjacent to the initiation interval. Understanding vertical hydraulic fracture growth through low porosity layers improves the hydraulic fracture design, enhances reservoir deliverability potential and enables the identification of infill well potential and intervention opportunities. The South Arne field is located in the northern part of the Danish sector of the North Sea. The Tor and Ekofisk formations are high porosity/low permeability chalks with low to moderate natural fracturing. Porosities may reach 45%, but a hard low porosity interval of 10% or less at the bottom of the Ekofisk formation separates and partially compartmentalizes (horizontally) the two formations. A series of indirect tensile strength measurements on South Arne cores were conducted. The measurements verified a suspected exponential increase in tensile strength at low porosities, essentially causing the tensile strength to exceed 1,500 psi in some cases. Recent 4D seismic surveys have enabled separate sweep patterns for each reservoir unit to be mapped and indicate that the sweep is much less efficient in the Ekofisk. This supports that the hydraulic fracture stimulation treatments initiated in the Tor formation are not accessing the upper units to the degree previously assumed and it appears that connection is occurring via pre-existing faults and/or natural fractures. The hydraulic fractures propagate nearly longitudinal to the wellbore, guided by regional stresses, with limited height growth. However, production effects, specifically compaction induced by draw down, may perturb the stress field sufficiently so that the preferred alignment is not achieved, further reducing sweep efficiency. This is indicated by 3D coupled geomechanical modeling and is corroborated by 4D seismic observations.

In non-compliant sand control completions such as stand-alone-screens, the annular gap between the wellbore wall and the screen has always been considered detrimental to efficient inflow. They are typically associated with large skins resulting from the mixing of failed sand grains and the development of a new and continuously changing permeability as the collapsing material starts to compact onto the screen. Annular movement of sand grains and non-uniform bridging creating "hot" spots will eventually lead to erosion and completion failure. Previous researchers have 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 mechanical and flow process occurring as the wellbore wall collapses onto the screen surface. Constitutive models are used to characterise the mechanical behaviour of the failed material in terms of deformation and collapse of the near wellbore onto the screen. Continuous (foot-by-foot) inflow models are presented to illustrate the impact of the deformation process as the annular gap is filled up on inflow. A detailed laboratory testing program and its results are presented to validate both processes using samples from North Sea sandstone reservoirs. The results indicate that for non-compliant sandface completions such as stand-alone screens, it is possible to determine whether the collapse of the wellbore will occur and how productivity will be affected. From the mechanical point of view the rock follows an extension-dilatancy-compaction path. This will at the same time produce a varying permeability and hence inflow, the magnitude of which will depend on factors such as pore pressure, drawdown pressures, reservoir rock mechanical properties and mineral composition. This extensive testing program has led to the development of a series of analytical models, testing procedures and design methodologies for wells being completed with non-compliant sand control completions.

Estimating formation permeability as a function of porosity, grain size, and the quantity and structure of fines is important for increasing hydrocarbon extraction from rock formations. The Kozeny-Carman equation can be used to estimate the permeability of clean unconsolidated media as a function of porosity and grain size, but does not account for the quantity and structure of deposited fines. This study shows how incorporating the volume of fines and a dimensionless bulk factor into the Kozeny-Carman equation can be used to model how the quantity and structure of deposited fines controls permeability. Several experimental studies from the literature are analyzed, representing a variety of fines (type and diameter), porous media, fluids, and flow velocities. These studies indicate that, when other variables are held constant, experiments conducted at higher flow velocity result in less plugging. For each experiment, a dimensionless bulk factor in the Kozeny-Carman equation was fitted, using the root mean square method, to best match the experimental data. Fitted values of the bulk factor were then correlated with the Peclet number to investigate how the structure of fines, quantified by the bulk factor, depends on the characteristics of the porous media, the depositing colloids, and the flow velocity. Larger bulk factors are observed at lower Peclet number, when diffusive transport dominates, which could result from more dendritic deposits. Smaller bulk factors are observed at higher Peclet numbers, when advective transport dominates, which could result from deposits that are more compact. By understanding how the bulk factor, and therefore the extent of permeability reduction, depends on the Peclet number, pumping schemes can be optimized in order to enable more complete hydrocarbon recovery. The primary application of this work is to optimize well flow rates to prevent or manage formation damage (i.e., plugging) resulting from deposition of fines in initially clean unconsolidated porous media.

Filter cake characterization is very important in drilling and completion operations. The homogeneity of the filter cake affects the properties of filtration process such as the volume of filtrate, the thickness of filter cake, and the way to remove it. Different models were used to determine the thickness and permeability of the filter cake. These models assume that the filter cake is homogeneous. The objective of this study is to measure the filter cake thickness and permeability of water-based drilling fluids by a new approach and compare the results with previous models. A HPHT filter press was used to perform the filtration process under static conditions (225°F and 300 psi). CT (computed tomography) scan was used to measure the thickness and porosity of the filter cake. SEM was used to provide the morphology of the filter cake. Leica microscope was used to determine particle size distribution. The results obtained from the CT scan showed that the filter cake was heterogeneous and contained two layers with different properties. The average thickness of the external layer was 0.1 in., which was greater than the average thickness of the internal layer (0.06 in.). Both the porosity and permeability of the external layer were zero, while the porosity of the internal layer ranged from 10 to 20 vol. %. SEM results showed that the two layers contained large and small particles but there was a very poor sorting in the external layer, which led to zero porosity in this layer. Previous models underestimated the thickness of the filter cake by almost 50%. A new method was developed to predict the thickness and permeability of the two-layer filter cake. This method predicted the experimental data very well.

In the Danish Central Graben, the Lower Cretaceous reservoir contains significant in-place oil volumes. This formation historically has posed a real challenge to develop because of the extremely low permeability. The low permeability is compounded by the fact that the formation is soft, highly heterogeneous, and can have significant clay content in some areas. Although the Lower Cretaceous chalks represent a wide spread play in the central North Sea, there are no producing analogs. Thicker Lower Cretaceous reservoir sections in the Valdemar field have been successfully proppant fracture stimulated. Acid stimulation is preferred for the thinner sections; however, early attempts at matrix acid stimulation were very disappointing. Recently, the need to re-enter a well for maintenance allowed three zones to be selectively restimulated using improved execution techniques and a more appropriate acid formulation. Production increase following restimulation of this first well was very encouraging and the lessons learned were applied to a second well; this time a newly drilled well completed in the Tyra Lower Cretaceous reservoir. This paper summarizes the lessons learned, starting with a review of the previous acid stimulations. Wormhole testing with Lower Cretaceous core material provided important insight toward the selection of the most appropriate acid formulation. Computer modeling was used to determine the most effective perforation patterns, based upon variable formation characteristics along the long, horizontal wellbore. Treatment execution and monitoring included diagnostic injection tests and real-time calculations of acid coverage during the limited-entry perforated completions. The results of these two wells has been very encouraging and has opened up the possibility for continued testing of acid stimulation techniques in both the Valdemar and Tyra Lower Cretaceous reservoirs.

Abstract This paper describes the study of the effect of asphaltene precipitation and deposition on the development of the Marrat field using a compositional simulation model with asphaltene modeling facilities. The model enables the simulation of asphaltene precipitation, flocculation, and deposition including adsorption, plugging, and entrainment, and the resulting reduction in porosity and permeability and changes in oil viscosity and rock wettability. A workflow was established in the study to i) characterize the equation of state (EOS) by analyzing the fluid PVT and asphaltene data from the lab; ii) calibrate the asphaltene model input parameters using the core flood experimental data; and iii) incorporate the EOS and the asphaltene parameters into the full field simulation model. The model was used to analyze the effects of asphaltene on various development scenarios, including depletion and water injection. For each scenario, the following were calculated and analyzed: field performance including production of oil, gas, and water; asphaltene behavior including precipitation, flocculation, adsorption, plugging and entrainment; formation damage and the effect of rock wettablity changes. The results show that the formation could be severely damaged near the producers where asphaltene is more likely to precipitate because of lower pressures (below the asphaltene onset pressure) and longer time exposure to a larger amount of oil. Formation damage could be reduced by flushing away the deposited asphaltene using higher flow rates if plugging is not significant. The water injection scenario with higher injection rate and higher production rate with BHP limit above 6,000 psia results in less asphaltene adsorption, more entrainment, and therefore less deposition. This in turn causes less permeability damage and more oil production. Introduction The Kuwait Oil Company (KOC) encountered the problem of asphaltene precipitation in Jurassic production wells located in producing areas in West and South East Kuwait. In West Kuwait (WK), the Jurassic production is primarily from the Marrat field. Out of about 45 wells in WK-Marrat 50% have a history of asphaltene cleanouts. These wells contribute to around 7% of the total oil production from WK which can amount to as much as 50 Mbbl/d. Here the reservoir pressure (around 9,500 psi) is considerably above the asphaltene onset pressure (AOP) (estimated between 2,000 psi to 4,000 psi). Therefore, there is no likelihood of asphaltene deposition in the reservoir. However, during production as the pressure of the produced fluid inside the tubing goes below the AOP, asphaltenes start to precipitate from the crude. Asphaltenes gradually deposit in the tubing, reducing its diameter, and in the process cause production rates to drop; eventually the well completely ceases to flow. Once this has occurred, the tubing in the well must be cleaned out to restore the well to production. The Marrat reservoir lies in the South Eastern part of Kuwait, within the giant Burgan field complex. It is a carbonate reservoir, existing at an average depth of 11,000 to 11,500 ft, subsea. The reservoir fluid is generally light, ranging in quality between 36 and 40 API degrees. The original oil in place is estimated to be two billion stock tank barrels. The original reservoir pressure at discovery was determined to be 9,650 psia. A log with the average properties of the reservoir is shown in Figure 1. The fluid is known to be asphaltenic 1 in nature, as evidenced by the deposition of asphaltenes in the production strings and surface production facilities, requiring periodic cleanup and treatment operations. In South and East Kuwait, all the wells in the Marrat reservoir were closed from 1998 to avoid further drop in the reservoir pressure, which had already dropped close to the AOP (the present reservoir pressure is around 8,400 psi and AOP ranges from 5,500 psi to 6,700 psi). Further reduction in reservoir pressure below the AOP could cause asphaltene deposition in the reservoir itself and result in formation damage. The decision was made to produce the wells only after a comprehensive development plan for reservoir pressure maintenance with implemented water injection.

Abstract It is well known that in higher-permeability natural gas reservoirs turbulence, at times referred to as non-Darcy effects, may become the dominant influence on production. For vertical wells turbulence has been relatively well understood, deliverability equations have been adjusted to account for the phenomenon and, correlations have been presented a long time ago. Furthermore, field-testing techniques have been established to obtain the non-Darcy coefficient. Surprisingly, similar work has not been done for horizontal wells. One of the reasons is that horizontal wells have been the completion of choice in North America primarily for very low permeability reservoirs where turbulence effects are of no consequence. However, as the international petroleum industry starts looking at high-permeability gas reservoirs, turbulence effects in horizontal wells can no longer be ignored. Past work on the subject has been sketchy and in the one or two literature sources where it was addressed, the calculations are demonstrably wrong, not taking into account the crucial near-well effects. Also, quite important is that the few turbulence correlations used in the past, for some unexplainable reason have ignored the porosity. We present here appropriate correlations to account for turbulence effects in horizontal wells and show that while horizontal wells, even with turbulence, provide considerably higher performance than vertical wells, the reduction from ideal expectations can be substantial. For example, at a permeability of 100 md, while for vertical wells the reduction between real and ideal production may approach 40%, for horizontal wells, it may approach 30%. The influence of porosity is considerable and can account for another 30% deviation among reasonable porosity values. We finally offer a large range of parametric studies that involve reservoir thickness, permeability anisotropy and horizontal well length. Turbulence effects have a tendency to reduce the expected beneficial ideal effects from longer wells or permeability isotropy because of the implicit "suicide" effects deriving from higher production rates. Introduction Horizontal wells outside of the former Soviet Union started in the 1980s and, eventually, were widely introduced in the early 1990s. Since then, they have proliferated and have become essential in oil and gas production (Economides and Martin, 2007). The main advantages of horizontal wells are (Joshi, 1991, Cho and Shah, 2001): To increase productivity as the wellbore is longer than that of vertical well; To reduce water or gas coning; To reduce turbulence in gas wells (emphasis ours); To intersect fractures in naturally fractured reservoirs and drain reservoirs more effectively; To improve drainage area per well and reduce the number of vertical wells in low permeability reservoirs; To increase injectivity of an injection well and enhance sweep efficiency. There are quite a few important publications related to horizontal well performance (Celier et al., 1989, Dikken, 1990, Joshi, 1991, Norris et al., 1991, Ozkan et al., 1999, Economides et al ., 1994, Cho and Shah, 2001), but few of them had addressed turbulence effects on well performance. Of those that discussed turbulence, most assumed that turbulence is small and can be neglected. Their assumption is that the horizontal well length ( L ) is a lot longer compared to the vertical well height (h) and therefore, they concluded that turbulence is smaller in horizontal wells compared with that in vertical wells and could be neglected. This is true when the reservoir is isotropic and the permeability is small. But when permeability increases, well deliverability increases, and turbulence effects can no longer be neglected. Based on our study, the production loss due to turbulence could account for 30% in horizontal wells. When the reservoir is anisotropic, it gets even worse.

Abstract In the 21st century, the global gas demand will be met only by extensive production of unconventional gas (shale and tight sand gas, deep gas, basin concentrated gas accumulation, etc.). All such gas-bearing formations are characterized, however, by extremely low, usually micro Darcy range permeability. Unfortunately, the operators of such reservoirs face with difficulties when routine drilling, well completion, fracturing, and production technologies are used. One source of the problems can be traced back to use of water-base fluids. Therefore, the laboratory studies aimed at elucidating the reasons why water-based fluids are harmful and seriously jeopardize the gas production from such reservoirs. The water induced formation damage is illustrated in a porous media having 0.001–0.1 mD permeability and obtained from a tight sand gas formation. Its pore structure was analyzed by HP Hg porosimetry and the wettability was determined by digital image analysis. The spontaneous imbibition was tested with standard method. Surface tension of water was determined by automatic ring method. The critical Pc needed to mobilize water was calculated as a function of pore size distribution. Using the relevant data (pore size distribution, wettability and surface tension) the calculated Pc was in range of 40–75 bar for cores obtained from medium depth (3600 m); meanwhile it was extremely high, 500–600 bar for cores derived from deeper layers (>6000 m). Based on these data it was concluded that the native water saturation should be high (>70%) and immobile in similar formations and because of the high imbibition rate the water behaves as a potential blocking phase in the cores. The mentioned factors seriously influence both the resource/reserve assessment and the production efficiency. Since the water may induce formation damage hard to control, application of water free fluids is recommended in any phase of field operation at unconventional gas reservoirs. Introduction Energy demand is expected to quadruple in the 21st century. An energy mix that is undergoing a transition from the current dominance of fossil fuels to a more balanced distribution of energy sources will meet the energy demand. Although the relative importance of hydrocarbons apparently will decrease from 60% (present) to 15% (in 2100), roughly 250–260 billion t of crude oil (annually 2.5 billion t on average through the whole century) must be produced to meet the worldwide demand. Because of high demand, the production lifetime is only 40 years for oil. The global situation in natural gas seems to be better, but not comforting. According to a widely accepted forecast, the proved (industrial) reserve reported by BP Statistical Review 1 is 179.53 Tm 3 by the end of 2007. According to the US Geological Survey 2 , the undiscovered gas resources total up to a probable maximum of 147.16 Tm 3 , that is already less than the proved industrial reserves. Actually, the available world gas reserve is much lower if the gas recovery coefficient is less than the unity (100%).

Abstract In this paper we describe a simulation model for computing the formation damage imposed on the formation during over-balanced drilling. The main parts modelled are filter cake build-up under both static and dynamic conditions, fluid loss to the formation, transport of solids and polymers inside the formation including effects of pore lining retention and pore throat plugging, and salinity effects on fines stability and clay swelling. The developed model can handle multi-component water-based mud systems at both the core scale (linear model) and the field scale (2D radial model). Among the computed results are fluid-loss versus time, internal damage distribution and productivity calculations for both the entire well and individual sections. The simulation model works in part independent on fluid loss experiments, e.g., we do not use fluid leakoff coefficients, but instead we compute the filter cake buildup and its flow resistance from properties ascribed to the individual components in the mud. Some of these properties can be measured directly, such as particle size distribution of solids, effect of polymers on fluid viscosity and formation permeability and porosity. Other properties, which must be determined by tuning the results of the numerical model against fluid loss experiments, are still assumed to be rather case independent, and once determined they can be used in simulations at altered conditions as well as with different mud formulations. A detailed description of the filter cake model is given in the paper. We present simulations of several static and dynamic fluid loss experiments. The particle transport model is used to simulate a dilute particle injection experiment taken from the literature. Finally, we demonstrate the model's applicability at the field scale and present computational results from an actual well drilled in the North Sea. These results are analysed and it is concluded that the potential impact of the mechanistic modelling approach used is (a) increased understanding of damage mechanisms, (b) improved design of experiments used in the selection process and (c) better predictions at the well scale. This allows for a more efficient and more realistic pre-screening of drilling fluids than traditional core plug testing. Introduction A simulation tool, referred to as Maximize, has been developed for the purpose of investigating fluid loss to the formation during over-balanced drilling and the impairment imposed on the formation by the invading fluid. The objective of the program is to serve as a tool for supporting well planners' decisions related to the choice of well fluids, and integrating, analyzing and interpreting laboratory as well as field formation damage data. The filtration properties of the mudcake forming at the wellbore surface has been investigated by several authors over the years, see for example Ferguson and Klotz (1954); Outmans (1963), Bezemer and Havenaar (1966), Arthur and Peden (1988), Fordham et al. 1991 and Dewan and Chenevert (2001). The common understanding is that once the filter cake has been formed, it will control the filtration rate independent of the formation properties, except at very low permeability where the flow resistance offered by the formation is comparable to the filter cake resistance. The filter cake properties depend only on its composition, the pressure drop over the cake Dp and the shear stress acting on the cake surface by the circulating mud. Under dynamic conditions, the filtration rate will approach asymptotically a limiting steady-state rate which only depends on the shear stress at the cake's surface. A combined filter cake and simulation model was used by Semmelbeck et al. (1995) for computing the fluid invasion profile along the well. Further improvement of the filter cake model was presented by Dewan and Chenevert (2001), who demonstrated the derived model's capability to reproduce complex laboratory experiments with sequential changes in dynamic shear rate and overbalance pressure. Others, have also investigated filtrate invasion by numerical simulations e.g., Ding et al. (2002), Wu et al. (2004) and Suryanarayana et al. (2005).

Abstract Due to low sand strength the preferred completion method for the Heidrun field is gravel packed screens. This has proven to be a well suited sand control method. However, some failures have been encountered with the subsequent loss of the well or a reduced production rate due to sand production. Some of these failures are related to water break through which can induce the production of fines and result in plugging and erosion of the sand screens. When these type of failures result in the onset of massive sand production, it is a challenge to handle the well properly. How do we best produce the well to avoid it being filled with sand, and how do we best identify the point of failure? Identifying a failed sand screen is not straight forward since it is situated on the outside of a perforated base pipe, and no direct measurements can be achieved. This paper describes a method used on several wells in the Heidrun field to mitigate failures in gravel packed screens. The method described, includes; how to identify sand production, the preferred way to run the well after sand production has been identified and how to perform data acquisition to determine the point of failure. The data acquisition described includes gravel pack logging, injection logging and saturation logging. This method has been used with success on several wells in the Heidrun field, wells which would have been considered lost otherwise. Introduction to the Heidrun Field The Heidrun field is located on Haltenbanken in the Norwegian Sea. The sea depth in the area is 350m. The field has been developed with a floating concrete tension leg platform (TLP), installed over a subsea template with 56 well slots. The northern part of the field is developed with 5 subsea templates. The field's oil and gas production started on October 1995. The reservoir consists of sandstones in the Garn, Ile, Tilje and Aare formations of Early and Middle Jurassic age. The reservoir is heavily faulted. The Garn and Ile formations have good reservoir quality, while the Tilje and Aare formations are more complex. Most of the formations produced on the Hedirun field have a moderate to low sand strength, and are prone to sand production. Several approaches to sand control has been tried, and the current base case solution is open hole gravel packed screens. The recovery strategy for the field is pressure maintenance using water and gas injection.

Abstract Previously, we have studied the acidization of vuggy carbonates with acid core flood experiments in 4-inch diameter by 20-inch long cores, high resolution computerized tomography imaging, image processing and geostatistical characterization. The obvious major finding from these tests is that acid propagates wormholes through vuggy carbonates much more rapidly than occurs in more homogeneous rocks. Acid-created wormholes were observed to break through to the end of the cores an order of magnitude more rapidly than occurs in more homogeneous cores, highlighting the necessity of understanding the flow and transport in vuggy carbonates. The fact that acid channeled through the vugular cores, following the path of the vug system, was underlined with computerized tomography scans of the cores before and after acid injection. This observation proposes that local pressure drops created by vugs are more dominant in determining the wormhole flow path than the chemical reactions occurring at the pore level. Following this idea, we are presenting a modeling study in order to understand flow in porous media in the presence of vugs. Use of coupled Darcy and Stokes flow principles, known as the Darcy-Brinkman formulation, underpins the proposed approach. The power of the Darcy-Brinkman formulation lies in its natural ability to represent both porous media and tube flow in a single equation with variable coefficients. The methods presented here shows that acid injected into vuggy limestones follows a preferential pathway guided by the vug network. The PVbt (pore volumes to break through) for vuggy limestone correlates inversely with the fraction of total porosity comprised by vugs - the higher the vuggy fraction of porosity, the lower the pore volumes to breakthrough. Local pressure drops created by vugs are more dominant in determining the wormhole flow path than the chemical reactions occurring at the pore level. The results from the developed model demonstrate that the total injection volume to breakthrough is affected by the spatial distribution, the amount and the connectivity of vuggy pore space. Introduction Matrix acidizing is a technique that has been used extensively since the 1930s to improve production from oil and gas wells and to improve injection into injection wells. Matrix stimulation is accomplished by injecting a fluid (e.g., acid or solvent) to dissolve and/or disperse materials that impair well production in sandstones or to create new, unimpaired flow channels between the wellbore and a carbonate formation. The principle of a matrix acidizing treatment in carbonate reservoir is to bypass near well-bore damaged region by creating highly conductive channels known as wormholes. When the reaction rate is rapid, the larger pores tend to grow much more rapidly than do the smaller ones. This gives rise to a phenomenon known as wormholing in which a few large holes form and conduct all, or nearly all, of the acid (Schechter 1992). The success of the stimulation depends on the ability of the engineer to control the unstable process creating the wormholes. Studies show that more than 35% of matrix treatment failed, or did not reach expectations (Sengul and Remisio 2002). In some cases excessive water production was reported because of an inappropriate design. Another consequence of inappropriate design is pore collapse because of the over treatment. Optimized design gains much more attention when horizontal wells come to picture. Since the volume of acid to stimulate these wells is huge, a well designed acid treatment plan has great importance.

ABSTRACT The existence of sulfur compounds in crude oils decreases their economical value and creates many problems of sulfur deposition in the vicinity of a wellbore hole, in well completion and/or production equipment, and in producing reservoir rocks. Laboratory testing of carbonate reservoirs containing sulfur and asphaltene shows that carbon dioxide flooding is likely to be more efficient if these reservoirs have permeabilities near 10 md than higher levels. Furthermore, faster production rates are likely to reduce displacement efficiency as the contaminants deposit in porous medium and increase damage. Likewise, crude oil viscosity increases with increase of sulfur and asphaltene contents for different temperatures. Eight core flooding experiments were conducted using multiple flow rates, and reservoir rock permeabilities. All runs were conducted at secondary mode (no water flooding) using carbon dioxide slug size of 15 % hydrocarbon pore volume (HCPV). Three other runs using different initial oil saturations were also performed to study the effect of mobile oil saturation. Our results suggest that application of CO 2 flooding to these reservoirs could exacerbate damage to the reservoir porous rocks. 1. INTRODUCTION AND LITERATURE REVIEW Sulfur is present as a dissolved species in sour gas and oil reservoir, its precipitation may be induced by thermodynamic changes of saturation point that causes a reduction in the solubility of the sulfur in the gas or liquid oil phases. Sulfur compounds are considered the most unfavorable non-hydrocarbons in crude oils; because of their corrosive nature, their deleterious effects on petroleum products, their tendency to plug porous medium, which may impair formation productivity, their effect on oxidation characteristics, and their environmental deteriorations. Gaseous carbon dioxide has a density of 0.00198 gm/ml at 0 °C and 1.0 atmosphere, and it is not effective as a solvent for liquids under these conditions. Increasing pressure increases the density of carbon dioxide because solubility increases in organic compounds. When the temperature increases to 31 °C (88 °F critical temperature) with an increase of pressure, the difference in densities of saturated gas and liquid is small and the two phase condition does not exist. Above 31 °C (88 °F) and 73 atm (1071 psi, critical pressure), supercritical CO 2 fluid exits in only one phase, Fig. 1. Supercritical CO 2 is unique and in that acts chemically like a liquid and physically like a gas. The solvating power of a liquid CO 2 increases as its density increases and the more substrate the fluid can extract from the reservoir matrix (Pipkin, 1990). Huang and Ortiz (2000) injected CO 2 at pressure of 1,100 to 1,200 psi to ensure that the CO 2 reached the supercritical condition in the McElroy field of Permian basin in Texas. Hawthorne et al. (1994) found that the low polarity of supercritical CO 2 causes the precipitation of asphaltene and perhaps other heavy organic components and/or oxygen containing compounds.

Abstract Traditionally the oil and gas industry has identified formation damage as the one caused by the drilling process such as filtrate and solid's invasion. Other types generated during the completion and production phases normally occur while perforating or during hydrocarbons production, typically fines production, asphaltenes deposition, changes in formation wettability and scaling. On the other hand, mechanical damage defined as that induced by stresses is seldom considered or even measured, it is poorly understood and very difficult to identify. Solid's invasion from the drilling fluid and permeability change at the sand face are the two damage mechanisms discussed in this paper. Both mechanisms are treated using conventional filtration theory and plastic rock behaviour principles. On this basis our paper presents a methodology developed for the identification, quantification and removal of formation damage caused by these two mechanisms in new wells. Quantification of both types of damage on a continuous basis throughout the sandstone is carried out to determine the location and severity of the combined mechanisms. Introduction The drilling process involves the cutting and removal of rock that is transported to surface by the circulating fluid. In most circumstances the pressure exerted by the fluid is higher than that of the formation establishing a pressure over balance condition between the circulating pressure and the reservoir pressure. In porous and permeable sandstones, this over balance condition induces the penetration of drilling fluid into the rock matrix. Fluids and solids penetrate the matrix invading it until the solids contained in the mud plug the pore throats forming a semi permeable barrier known as the mud cake. The depth of invasion for both fluid and solids is dictated by the rock properties, pressure differential and the mud properties. Filtration theory and plugging 1,2 principles are used to characterize the invasion mechanisms, type and penetration of the fluids and solids into the matrix. At the same time the pressure exerted by the drilling fluid tries to compensate the main stresses acting upon the formation at the wellbore wall. This pressure is variable as the friction factors and fluid density changes with variations in the drilling process (i.e. pump rates, ROP, solid's loading, hole size…). This results in a continuous change of stresses around the wellbore during drilling that lead to deformation or even formation failure. This phenomenon has been widely documented 3,4 and at the wellbore wall resulting in the generation of a zone that has changed from an elastic to a plastic condition. The extent of this zone can be determined using the equations included in appendix 1. This change also means a change in formation petrophysical properties throughout its width and length as it is illustrated in figure 1. In practical terms the two mechanisms (filtration and deformation) occur almost "simultaneously" during drilling and result in a distinctive zone with very different properties to those of the unaltered sandstone reservoir rock. In contrast with what is presented in petroleum engineering literature this damaged zone is not only invaded reservoir rock but deformed and invaded reservoir rock. There is a significant difference between both terms as the latter implies mechanically unaltered rock whose matrix has been invaded by solids and mud filtrate, the former implies rock invaded in a similar manner but that has changed its initial properties as a result of the stresses in the near wellbore area. These changes in the rock mechanical state are induced by changing stress as initially described, a plastically deformed rock such as the one described above leads to a two (2) permeabilities zone as reported in the literature 5.

Abstract The Joint Chalk Research (JCR) initiative is set up by a group of operators and partners in the Southern North Sea. The objective of the initiative is to increase the ultimate recovery in their respective chalk assets to 60%. Analyzing the different production technology options used in the assets thus far was the next step in better understanding the different recovery increment options. The initial 4 year productivity from 4 assets was analyzed. This paper presents the results of a study focused on increasing the understanding of productivity drivers using a database on well productivity related to different completions, stimulations and production options. The database contains 56 wells from 4 different assets and 750 acid and proppant treatments in 663 perforated intervals. It was found that the absolute total production per interval is similar for all assets; however the drawdown applied in 1 asset is 4 times lower than the other assets. The performance of the wells in most assets dropped strongly over time, except in the low drawdown asset. It was found that in addition to transient effects, it is likely that a decline in hydraulic fracture completion efficiency also contributes to this decrease in production performance. The low drawdown asset has a much better normalized production performance than the other assets. Other factors might also influence this result, however, compelling evidence has been found that the much lower drawdown may cause the better performance over time. The normalized recovery of propped fracced wells was better than the acid treated well in 2 of 3 assets using both stimulation types. The higher recovery of the propped treatments was mainly from better productivity over time compared with the acid fracture treatments. However, the initial productivity of the acid fractured well was much better, hence the economic balance could still tip to the acid treatments. The analysis showed that, for all assets except one, there is a significant difference in the performance of acid fractured wells and propped fractured wells over time. Indications are that production declines are not only due to depletion, but also related to deterioration of the completion efficiency as a function of pressure drawdown and suboptimal efficiency of acid treatments. An extensive statistical analysis indicated a strong dependency on asset grouping, which hampers the extrapolation of experience from one asset to the others. Introduction This paper presents a study on well productivity from chalk fields in the North Sea as a function of different stimulation, completion and production techniques. The objective of the study was to enhance the understanding of productivity drivers by developing, and analyzing a database on well productivity related to different completions, stimulations and production options. The focus of this study was on a technical and statistical analysis; the economic evaluation of the well productivity was specifically left out of this study. However, all the necessary data for an economic evaluation (except a few cost items) can readily be retrieved from the database. All assets included in this study are situated in the Southern Central Graben in the North Sea in relative close proximity to each other. The assets are producing oil from chalk depositions, about three kilometres below sea level. The hydrocarbon bearing formations were formed in the late Cretaceous, early Paleocene, about 60 to 70 million years ago. The formations were formed in a shallow to open marine depositional environment.